-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, WQy0GRtr0qezn2zBd2JxpcYLlieVkcqF4x0TgICmql76hnu2E9zhh0TWwlquOGrz t738vJB8xMhFhi0IxbR3MQ== 0000899243-01-000125.txt : 20010123 0000899243-01-000125.hdr.sgml : 20010123 ACCESSION NUMBER: 0000899243-01-000125 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20010118 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PLAINS RESOURCES INC CENTRAL INDEX KEY: 0000350426 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 132898764 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: SEC FILE NUMBER: 001-10454 FILM NUMBER: 1510994 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: STE 700 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136541414 MAIL ADDRESS: STREET 1: 1600 SMITH STREET STREET 2: SUITE 1500 CITY: HOUSTON STATE: TX ZIP: 77002 10-K/A 1 0001.txt AMENDMENT #1 - 12/31/1999 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K/A Amendment No.1 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999 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) SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Name of each exchange Title of each class on which registered ------------------- --------------------- Common Stock, par value $0.10 per share American Stock Exchange 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 [ ] On March 15, 2000, there were 17,948,856 shares of the registrant's Common Stock outstanding. The aggregate value of the Common Stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant, for this purpose, as if they may be affiliates of the registrant) was approximately $243,674,442 on March 15, 2000 (based on $13 15/16 per share, the last sale price of the Common Stock as reported on the American Stock Exchange Composite Tape on such date). DOCUMENTS INCORPORATED BY REFERENCE: The information required in Part III of the Annual Report on Form 10-K is incorporated by reference to the Registrant's definitive proxy statement to be filed pursuant to Regulation 14A for the Registrant's Annual Meeting of Stockholders. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] ================================================================================ PLAINS RESOURCES INC. AND SUBSIDIARIES 1999 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS
PAGE ---- PART I Item 1. Business.............................................................................. 3 Item 2. Properties............................................................................ 29 Item 3. Legal Proceedings..................................................................... 33 Item 4. Submission of Matters to a Vote of Security Holders................................... 33 PART II Item 5. Market for Registrant's Common Stock and Related Stockholder Matters.................. 35 Item 6. Selected Financial Data............................................................... 36 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 38 Item 7a. Quantitative and Qualitative - Disclosures About Market Risks......................... 51 Item 8. Financial Statements and Supplementary Data........................................... 52 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 52 PART III Item 10. Directors and Executive Officers...................................................... 52 Item 11. Executive Compensation................................................................ 52 Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 52 Item 13. Certain Relationships and Related Transactions........................................ 52 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K....................... 53
FORWARD-LOOKING STATEMENTS This annual report on Form 10-K/A contains forward-looking statements and information that are based on our beliefs, as well as assumptions made by, and information currently available to us. 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. Such 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 law, we do not intend to update these forward-looking statements and information. DEFINITIONS OF OIL AND GAS TERMS As used in this report, "Bbl" means barrel, "MBbl" means thousand barrels, "MMBbls" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Btu" means British Thermal Unit, "Mbtus" means thousand Btus, "BOE" means net barrel of oil equivalent and "MCFE" means Mcf of natural gas equivalent. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. A "working interest" is a cost-bearing interest under an oil and gas lease that gives the holder the right to produce and develop the minerals under the lease. A "net revenue interest" is the lessee's share of production after satisfaction of all royalty and other non cost-bearing interest. A "gross acre" is an acre in which an interest is owned. The number of "net acres" is the sum of the fractional working interests owned in gross acres. "Net" oil and natural gas wells are obtained by multiplying "gross" oil and natural gas wells by our working interest in the applicable properties. "Present Value of Proved Reserves" means the present value (discounted at 10%) of estimated future cash flows from proved oil and natural gas reserves, as estimated by our independent engineers, reduced by additional estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes). The present value of proved reserves is calculated using product prices in effect on the date of determination. "Standardized Measure" is such amount further reduced by the present value (discounted at 10%) of estimated future income taxes on such cash flows. "NYMEX" means New York Mercantile Exchange. 2 PART I ITEMS 1. BUSINESS GENERAL We are an independent energy company that is 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. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in Plains All American Pipeline, L.P. ("PAA"). One of our wholly owned subsidiaries, Plains All American Inc., is both the general partner and majority owner of PAA. Because it holds the general partner interest and owns approximately 18.2 million common and subordinated units, Plains All American Inc. holds an approximate 54% interest in PAA. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. The following chart sets forth the organization relationship of the subsidiaries in our two lines of business: [PLAINS RESOURCES ORGANIZATIONAL CHART] 3 UNAUTHORIZED TRADING LOSSES Background 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). 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 from March through November 1999, and 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. As a result, we have restated our previously reported 1999 and 1998 results to reflect the losses incurred from these unauthorized trading activities (see Note 3 in the notes to our consolidated financial statements appearing elsewhere in this report. Normally, as PAA purchases crude oil, it establishes a margin by selling crude oil for physical delivery to third parties, or by entering into future delivery obligations with respect to futures contracts. The employee in question violated PAA's policy of maintaining a substantially balanced position between purchases and sales (or future delivery obligations) by negotiating one side of a transaction without negotiating the other, leaving the position "open." The trader concealed his activities by hiding open trading positions, by rolling open positions forward using off-market, inter-month transactions, and by providing to counter-parties forged documents that purported to authorize such transactions. An "inter-month" transaction is one in which the receipt and delivery of crude oil are scheduled in different months. An "off-market" transaction is one in which the price is higher or lower than the prices available in the market on the day of the transaction. By matching one side of an inter-month transaction with an open position, and using off-market pricing to match the pricing of the open position, the trader could present documentation showing both a purchase and a sale, creating the impression of compliance with PAA's policy. The offsetting side of the inter-month transaction became a new, hidden open position. Investigation; Enhancement of Procedures Upon discovery of the violation and related losses, PAA engaged an outside law firm to lead the investigation of the unauthorized trading activities. The law firm retained specialists from an independent accounting firm to assist in the investigation. In parallel effort with the investigation mentioned above, the role of the accounting-firm specialists was expanded to include reviewing and making recommendations for enhancement of PAA's systems, policies and procedures. As a result, PAA has developed a new written policy document and manual of procedures designed to enhance its processes and procedures and improve its ability to detect any activity that might occur at an early stage. The new policy was adopted by the Board of Directors of Plains All American Inc. in May 2000; however, implementation of many of the procedures commenced in January 2000, based on information developed throughout the investigation and the review of the policies, processes and procedures. In March 2000, management hired another independent accounting firm to provide additional objective input regarding the processes and procedures, and to supplement management's efforts to expedite the implementation of the enhanced policies and automation of the processes and procedures. The procedures have now been implemented, although not all reports are fully automated. The procedures have been, and will continue to be, refined. To specifically address the methods used by the trader to conceal the unauthorized trading, in January 2000 PAA sent a notice to each of its material counter-parties that no person at PAA was authorized to enter into off-market transactions. In addition, PAA has taken the following actions: . PAA has communicated its trading strategies and risk tolerance to its traders by more clearly and specifically defining those strategies and risk limits in its written procedures. . The new procedures require (i) more comprehensive and frequent reporting that will allow PAA officials to evaluate risk positions in greater detail, and (ii) enhanced procedures to check compliance with these reporting requirements and to confirm that trading activity was conducted within guidelines. . The procedures provide a system to educate each employee who is involved, directly or indirectly, in PAA's crude oil transaction activities with respect to policies and procedures, and impose an obligation to notify the Risk Manager (a new, independent function that reports directly to the Chief Financial Officer) directly or any questionable transactions or failure of others to adhere to the policies, practices and procedures. . Finally, following notification to each of its material counter-parties that off-market trading is against PAA's policy and that any written evidence to the contrary is unauthorized and false, the Risk Manager and other PAA representatives have also communicated our policies and enhanced procedures to our counter-parties to advise them of the information we will routinely require from them to assure timely recording and confirmation of trades. We can give no assurance that the above steps will serve to detect and prevent all violations of PAA's trading policy; we believe, however, that such steps substantially reduce the possibility of a recurrence of unauthorized trading activities, and that any unauthorized trading that does occur would be detected before any material loss could develop. Effects of the Loss The unauthorized trading and associated losses resulted in a default of certain covenants under PAA's credit facilities and significant short-term cash and letter of credit requirements. See Item 7. -- "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources." Although one of our wholly-owned subsidiaries is the general partner of and owns 54% of PAA, the trading losses do not affect the operations or assets of our upstream business. The debt of PAA is nonrecourse to us. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities. Our $225.0 million credit facility is collateralized by our oil and natural gas properties. In December 1999, PAA executed amended credit facilities and obtained default waivers from all of its lenders. The amended credit facilities: . waived defaults under covenants contained in the existing credit facilities; . increased availability under PAA's letter of credit and borrowing facility from $175.0 million in November 1999 to $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001; . required the lenders' consent prior to the payment of distributions to unitholders; . prohibited contango inventory transactions subsequent to January 20, 2000; and . increased interest rates and fees under certain of the facilities. PAA paid approximately $13.7 million to its lenders in connection with the amended credit facilities. This amount was capitalized as debt issue costs and will be amortized over the remaining term of the amended facilities. In connection with the amendments, we loaned approximately $114.0 million to PAA. This subordinated debt is due not later than November 30, 2005. We financed the $114.0 million that we loaned PAA with: . the issuance of a new series of our 10% convertible preferred stock for proceeds of $50.0 million; . cash distributions of approximately $9.0 million made in November 1999 to PAA's general partner; and . $55.0 million of borrowings under our revolving credit facility. In the period immediately following the disclosure of the unauthorized trading losses, a significant number of PAA's suppliers and trading partners reduced or eliminated the open credit previously extended to PAA. Consequently, the amount of letters of credit PAA needed to support the level of its crude oil purchases then in effect increased significantly. In addition, PAA's cost of obtaining letters of credit increased under the amended credit facility. In many instances PAA arranged for letters of credit to secure its obligations to purchase crude oil from its customers, which increased its letter of credit costs and decreased its unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, certain of PAA's purchase contracts were terminated. As a result of these changes, aggregate volumes purchased are expected to decrease by 150,000 barrels per day, consisting primarily of lower unit margin purchases. Approximately 50,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 100,000 barrels per day is attributable to bulk purchases. As a result of the increase in letter of credit costs and reduced volumes, annual Adjusted EBITDA is expected to be adversely affected by approximately $5.0 million, excluding the positive impact of current favorable market conditions. Adjusted EBITDA means earnings before interest expense, income taxes, depreciation, depletion and amortization ("DD&A"), unauthorized trading losses, noncash compensation expense, restructuring expense, gain on unit offerings, linefill gain and extraordinary loss from extinguishment of debt. 4 RESULTS OF OPERATIONS For the year ended December 31, 1999, our Adjusted EBITDA, cash flow from operations and net loss totaled $139.1 million, $70.4 million and $25.3 million, respectively. Excluding the unauthorized trading losses, our net income for the year ended December 31, 1999 would have been $32.9 million. Cash flow from operations represents net income before noncash items. Cash flow from operations also excludes the unauthorized trading losses, noncash compensation expense, restructuring expense, gain on unit offerings, linefill gain and extraordinary loss from extinguishment of debt. Our upstream operations contributed approximately 38% of our Adjusted EBITDA for the fiscal year ending December 31, 1999, while our midstream activities accounted for approximately 62%. UPSTREAM ACTIVITIES Our upstream business strategy is to increase our proved reserves and cash flow by: . exploiting and producing crude oil and associated natural gas from our existing properties; . acquiring additional underdeveloped crude oil properties; and . exploring for significant new sources of reserves. We concentrate our acquisition and exploitation efforts on mature but underdeveloped crude oil producing properties that meet our targeted criteria. Generally, the properties that we consider acquiring and exploiting are owned by major integrated or large independent oil and natural gas companies and have produced significant volumes since initial discovery and also have significant estimated remaining reserves in place. Our management believes that it has developed a proven record in acquiring and exploiting underdeveloped crude oil properties where we can make substantial reserve additions and cash flow increases by implementing improved production practices and recovery techniques and by relatively low risk development drilling. An integral component of our exploitation effort is to increase unit operating margins, and therefore cash flow, by reducing unit production expenses and increasing wellhead price realizations. We seek to complement these efforts by committing a minor portion of our capital to pursue higher risk exploration opportunities that offer potentially higher rewards in areas synergistic to our acquisition and exploitation activities. As part of our business strategy, we periodically evaluate selling, and from time to time have sold, certain of our mature producing properties that we consider to be nonstrategic or fully valued. These sales enable us to focus on our core properties, maintain our financial flexibility, control our overhead and redeploy the sales proceeds to activities that have potentially higher financial returns. We are able to take advantage of the marketing expertise that PAA has developed through our marketing agreement with PAA, under which PAA is the exclusive purchaser/marketer of all our equity crude oil production. During the five-year period ended December 31, 1999, we incurred aggregate acquisition, exploitation, development, and exploration costs of approximately $436.6 million, resulting in proved crude oil and natural gas reserve additions (including revisions of estimates but excluding production) of approximately 204.9 million BOE, or $2.13 per BOE, through implementation of this business strategy. We spent approximately 97% of this capital in acquisition, exploitation and development activities and we spent approximately 3% on our exploration activities. To manage our exposure to commodity price risk, our upstream business routinely hedges a portion of its crude oil production. For 2000, we have entered into various arrangements under which we will receive an average minimum NYMEX West Texas Intermediate ("WTI") crude oil price of approximately $16.00 per barrel on 18,500 barrels per day (equivalent to 79% of fourth quarter 1999 crude oil production levels). Approximately 10,000 barrels per day of the volumes that we have hedged in 2000 will participate in price increases above the $16.00 floor price, subject to a ceiling limitation of approximately $19.75 per barrel. For 2001, we have entered into various arrangements under which we will receive an average minimum NYMEX WTI price of approximately $19.00 per barrel on 12,000 barrels per day, which is equivalent to 51% of our fourth quarter 1999 crude oil production levels. Of these volumes, 100% have full market price participation up to $27.00 per barrel, 50% have price participation between $27.00 per barrel and $30.00 per barrel and 100% have full market price participation at prices above $30.00 per barrel. All of our NYMEX WTI crude oil prices are before quality and location differentials. Because of the quality and location of our crude oil production, these adjustments will reduce our net price per barrel. Our management intends to continue to maintain hedging arrangements for a significant portion of our production. These contracts may expose us to the risk of financial loss in certain circumstances. Our hedging arrangements provide us protection on the hedged volumes if crude oil prices decline below the prices at which these hedges are set. But ceiling prices in our hedges may cause us to receive less revenue on the hedged volumes than we would receive in the absence of hedges. At December 31, 1999, the total market value of our crude oil subject to hedges exceeded the amounts we will receive under our hedged prices by approximately $21.0 million. 5 The following table sets forth certain information with respect to our reserves over the last five years. Our reserve volumes and values were determined under the method prescribed by the Securities and Exchange Commission ("SEC"), which requires the application of year-end crude oil and natural gas prices for each year, held constant throughout the projected reserve life. The benchmark NYMEX crude oil price of $25.60 per barrel used in preparing year-end 1999 reserve estimates was more than double the $12.05 per barrel used in preparing reserve estimates at the end of 1998. The year-end 1998 NYMEX crude oil price was the lowest year-end crude oil price since oil was deregulated in 1980.
AS OF OR FOR THE YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------- 1999 1998 1997 1996 1995 ---------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS) Present Value of Proved Reserves (1) $1,246,049(1) $226,943(1) $510,993 $764,774 $366,780 Proved Reserves (2) Crude oil and natural gas liquids (Bbls) 218,922 120,208 151,627 115,996 94,408 Natural gas (Mcf) 90,873 86,781 60,350 37,273 43,110 Oil equivalent (BOE) 234,068(1) 134,672 (1) 161,685 122,208 101,593 Reserve Replacement Ratio (3) 1,263% (229%)(4) 603%(5) 454% 647%(6) Reserve Replacement Cost per BOE (7) $ 0.68 $ (5.46) $ 2.71 $ 1.76 $ 2.14 Total upstream capital costs incurred $ 72,979 $100,935 $127,378 $ 51,255 $ 84,012 Percentage of total upstream capital costs attributable to: Acquisition 5% 10% 34% 7% 71% Development 89% 88% 65% 88% 27% Exploration 6% 2% 1% 5% 2% Year-end Crude Oil Price $ 20.94 $ 7.96 $ 13.91 $ 22.22 $ 15.55 Year-end Natural Gas Price $ 2.77 $ 1.68 $ 2.13 $ 2.79 $ 1.05
- ---------- (1) We have reduced the pre-tax present value of proved reserves and the future net revenues of certain properties to reflect applicable abandonment and hedging costs and with respect to the LA Basin Properties, a net profits interest owned by a third party. (2) A 50% net profits interest attaches to the net proceeds from approximately 7.0 million barrels of our proved reserves in the L.A. Basin at December 31, 1999. (3) The reserve replacement ratio is calculated by dividing (a) the sum of reserves added during each respective year through purchases of reserves in place, extensions, discoveries and other additions and the effect of revisions, if any (b) each respective years' production. (4) The reserve replacement ratio for 1998 is negative due to a negative volume revision related to low crude oil prices at December 31, 1998. (5) Pro forma as if the acquisitions of the Montebello and Arroyo Grande Fields occurred on January 1, 1997. Such acquisitions closed in March and November 1997, respectively, with effective dates of February 1, 1997, and November 1, 1997, respectively. (6) Pro forma as if the acquisition of the Illinois Basin Properties occurred on January 1, 1995. Such acquisition closed in December 1995 with an effective date of November 1, 1995. (7) Reserve replacement cost per BOE for a year is calculated by dividing upstream capital costs incurred for such year by such year's reserve additions. ACQUISITION AND EXPLOITATION Acquisition and Exploitation Strategy We are continually engaged in the exploitation and development of our existing property base and the evaluation and pursuit of additional underdeveloped properties for acquisition. We focus on mature but underdeveloped producing crude oil properties in areas where we believe substantial reserve additions and cash flow increases can be made through relatively low-risk drilling, improved production practices and recovery techniques and improved operating margins. Generally, we seek to improve a property's operating margin by reducing costs, investing capital to increase production rates and enhancing the marketing arrangements of the crude oil production. Once we identify a prospective property for acquisition, we conduct a technical review of existing production and operating practices to identify and quantify underexploitated value. If the initial studies indicate undeveloped potential, the various producing and potentially productive formations in the area are mapped in detail. Historical production data is 6 evaluated to determine if additional wells or other capital expenditures appear necessary to optimize the recovery of reserves from the property. Geologic and engineering information and operating practices utilized by operators on offsetting leases are analyzed to identify potential additional exploitation and development opportunities. A market study is also performed analyzing product markets, available pipeline connections, access to trading locations and existing contractual arrangements with the goal of maximizing sales and profit margins from the area. See "--Product Markets and Major Customers". A comprehensive plan of exploitation is then prepared and used as a basis for our offer to purchase. We seek to acquire a majority interest in the properties we have identified and to act as operator of those properties. We have in the past and may in the future hedge a significant portion of the acquired production, thereby partially mitigating product price volatility that could have an adverse impact on exploitation opportunities. If we successfully purchase properties, we then implement our exploitation plan by modifying production practices, realigning existing waterflood patterns, drilling wells and performing workovers, recompletions and other production and reserve enhancements. After the initial acquisition, we may also seek to increase our interest in the properties through acquisitions of offsetting acreage, farmout drilling arrangements and the purchase of minority interests in the properties. By implementing our exploitation plan, we seek to increase cash flows and enhance the value of our asset base. The results of these activities are reflected in additions and revisions to proved reserves. During the five-year period ending December 31, 1999, net additions and revisions to proved reserves totaled 129.7 million BOE or approximately 368% of cumulative net production for this period. These reserves were added at an aggregate average cost of $2.44 per BOE. This activity excludes reserves added as a result of our acquisition activities. Reserve additions related solely to our acquisition activities totaled 75.2 million BOE and were added at an aggregate average cost of $1.60 per BOE. The properties in our four core areas represent approximately 99% of total proved reserves at December 31, 1999. These properties were previously owned and operated by major integrated oil and natural gas companies and are comprised of underdeveloped crude oil properties that we believed to have significant upside potential that can be evaluated through development and exploitation activities. During 2000, we estimate that we will spend approximately $72.0 million on the development and exploitation of our upstream crude oil and natural gas properties. Set forth below is a discussion of these properties. Current Exploitation Projects The following table sets forth certain information with respect to our crude oil and gas properties (dollars in millions):
CALIFORNIA PROPERTIES -------------------------------------------- ARROYO POINT SUNNILAND ILLINOIS LA BASIN MONTEBELLO GRANDE MT. POSO ARGUELLO TREND BASIN ----------- ----------- ------ -------- -------- --------- --------- Year(s) Acquired 1992 1997 1997 1998 1999 1993/1994 1995 Year(s) Discovered 1924 - 1966 1917 1906 1926 1981 1943 1905 Proved reserves at acquisition - MMBOE 17.7 23.3 19.9 7.7 6.4 5.0 17.3 CUMULATIVE FROM ACQUISITION DATE: - --------------------------------- Direct acquisition, development and exploitation capital spent $ 174.7 $ 55.2 $ 27.3 $ 13.9 $ 1.8 $ 81.8 $ 79.6 Production - MMBOE 26.3 1.6 1.2 0.3 0.8 9.0 5.2 Cumulative gross margin(1) $ 199.4 $ 9.6 $ 5.0 $ 2.8 $ 4.0 $ 58.1 $ 51.4 Aggregate reserve addition cost $ 1.49 $ 2.72 $ 0.43 $ 1.74 $0.28 $ 2.50 $ 2.74 AS OF DECEMBER 31, 1999: - ------------------------ Proved Reserves - MMBOE 90.8(2) 18.7 62.4 7.6 5.6 23.7 23.8 Future Net Revenues(3) $ 1,197.2 $201.8 $800.1 $103.2 $47.8 $ 205.9 $277.9 Pre-tax Present Value of Proved Reserves(3) $ 535.0 $ 90.1 $264.3 $ 60.0 $40.5 $ 136.7 $115.5 % Proved Undeveloped 30% 20% 87% 55% 43% 34% 12% 1999 Unit Gross Margin $ 7.45 $ 8.83 $ 7.53 $ 7.92 $4.92 $ 2.48 $ 9.63 Estimated development and exploitation capital budgeted in 2000 $ 31.0 $ 3.0 $ 10.0 $ 7.0 $ 9.0 $ 2.0 $ 10.0
- ----------------------- (1) Represents revenues less production expenses from date of acquisition. (2) We own a 100% working interest in the LA Basin property. A 50% net profits interest attaches to the net proceeds from approximately 7.0 million barrels of our proved reserves in the L.A. Basin at December 31, 1999. (3) We have reduced the pre-tax present value of proved reserves and the future net revenues of certain properties to reflect applicable abandonment and hedging costs and with respect to the L.A. Basin Properties, a 50% net profits interest owned by a third party. Onshore California Properties. In 1992, we acquired Stocker Resources, a sole purpose company formed in 1990 to acquire substantially all of Chevron USA's producing crude oil properties in the LA Basin. Following the initial acquisition, we expanded our holdings in this area by acquiring additional interests within the existing fields, including all of Texaco Exploration and Production, Inc.'s interest in the Vickers Lease. We refer to all of our properties in the LA Basin acquired 7 prior to 1997 collectively as the LA Basin Properties. The LA Basin Properties consist of crude oil reserves discovered at various times between 1924 and 1966. We have performed various exploitation activities, including drilling additional wells, returning previously marginal wells to economic production, optimizing waterflood operations, improving artificial lift and facility equipment, reducing unit production expenses and improving marketing margins. Through these acquisition and exploitation activities, our net average daily production from this area has increased from approximately 6,700 BOE per day in 1992 to an average of 11,000 BOE per day during the fourth quarter of 1999. We expanded our operations in the LA Basin with the acquisition of the Montebello Field, and expanded into other California areas with the acquisition of the Arroyo Grande Field and the Mt. Poso Field. Combined, these three fields added approximately 50.9 million BOE to our proved reserves at the acquisition dates. In March 1997, we completed the acquisition of Chevron's interest in the Montebello Field for approximately $25.0 million, effective February 1, 1997. The assets acquired consisted of a 100% working interest and a 99.2% net revenue interest in 55 producing crude oil wells and related facilities and also included approximately 450 acres of surface fee land. The Montebello Field is located approximately 15 miles from our existing LA Basin operations. Our net average daily production from this field has increased from approximately 930 BOE per day at the acquisition date to an average of approximately 2,100 BOE per day during the fourth quarter of 1999. In November 1997, we acquired a 100% working interest and a 97% net revenue interest in the Arroyo Grande Field which is located in San Luis Obispo County, California from subsidiaries of Shell Oil Company ("Shell"). The Arroyo Grande field was discovered in 1906 and has produced approximately 11 MMBbls of crude oil or approximately 5% of the estimated original crude oil in place. The assets acquired included surface and development rights to approximately 1,000 acres included in the 1,500 acre unit. The field is under continuous steam injection and at the acquisition date, was producing approximately 1,600 barrels per day (approximately 1,500 barrels net to our interest) of 14 degree API gravity crude oil from 70 wells. The aggregate consideration for the Arroyo Grande Field consisted of (1) rights to a non-producing property interest conveyed to Shell, (2) the issuance of 46,600 shares of Series D Cumulative Convertible Preferred Stock with an aggregate stated value of $23.3 million, and (3) a five-year warrant to purchase 150,000 shares of our common stock at $25.00 per share. No proved reserves had been assigned to the rights to the property interest conveyed. Unit production expenses for the Arroyo Grande Field, which averaged $9.36 per BOE at the acquisition date, averaged $5.26 per BOE during the fourth quarter of 1999. Our net average daily production from this field was approximately 1,600 barrels per day during 1999. During 1998, we acquired the Mt. Poso Field from Aera Energy LLC for approximately $7.7 million. The field is located approximately 27 miles north of Bakersfield, California, in Kern County. At acquisition, the field was producing 900 barrels of crude oil per day of 15 - 17 degree API gravity crude and added approximately 7.7 MMBbls of crude oil to our proved reserves. Our net average daily production from this field was approximately 950 barrels per day during 1999. Offshore California Properties. In July 1999, Arguello Inc., our wholly owned subsidiary, acquired Chevron's interests in Point Arguello for approximately $1.0 million. The acquisition, which was funded from our working capital, had an effective date of July 1, 1999. The interests acquired include Chevron's 26% working interest in the Point Arguello Unit, its 26% interest in various partnerships owning the associated transportation, processing and marketing infrastructure, and Chevron's right to participate in surrounding leases and certain fee acreage onshore. We assumed Chevron's 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. Chevron retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities. Arguello Inc. is the operator of record for the Point Arguello Unit and has entered into an outsourcing agreement with a unit of Torch Energy Advisors, Inc. for the conduct of certain field operations and other professional services. At acquisition, gross production from the field was approximately 20,100 barrels of crude oil per day (approximately 5,200 barrels per day, net to our interest) from 25 wells located on 3 offshore platforms. The acquisition added approximately 6.4 MMBbls of crude oil to our proved reserves. Our net average daily production from this property was approximately 4,400 barrels per day during the six months we owned the property in 1999. As with our other properties, we intend to aggressively exploit Point Arguello to evaluate additional reserve potential identified during our acquisition analysis. Our exploitation plans for this property target improving the unit gross margin by lowering costs and increasing production volumes through production enhancement activities similar to those employed in our other properties. 8 Sunniland Trend Properties. We have a 100% working interest in four producing fields in South Florida located in the Sunniland Trend that were previously owned and operated by Exxon Corporation. We acquired 50% of our interest in the properties in 1993 and the remaining 50% in 1994. At the time of our initial acquisition, production net to our interest was approximately 900 barrels per day. As a result of increasing our interest to 100%, development drilling on the property, and the implementation of exploitation activities designed primarily to repair failed wells and to increase the fluid lift capacity of certain wells, our net production peaked at an annual average of 5,300 barrels per day in 1997. During 1999, production from this area averaged 2,600 barrels per day. The production decrease is due to downtime as a result of mechanical problems and the effects of natural decline. During 1998 and 1999, several wells in this area had mechanical problems and were not returned to production due to lower operating margins. We expect that the rate of production decline in this area will decrease as several wells have been returned to production due to higher crude oil prices and overall declined rates are flattening out. Illinois Basin Properties. In December 1995, we acquired all of Marathon Oil Company's producing and nonproducing upstream crude oil and natural gas assets in the Illinois Basin for approximately $51.5 million, including transaction costs. Our initial exploitation plan for the Illinois Basin Properties included improving the unit gross margin by decreasing unit production expenses and increasing price realizations. Unit production expenses for these properties, which averaged $12.00 per BOE in the fourth quarter of 1995, averaged approximately $8.64 per BOE during 1999. The primary focus of our development and exploitation program during 2000 for the Illinois Basin Properties will be directed towards development drilling, performing reservoir characterization and selecting chemical mixtures to potentially implement an alkaline-surfactant- polymer pilot enhanced oil recovery project. Our net average daily production from this property was approximately 3,000 barrels per day during 1999. General. We believe that our properties in our four core areas hold potential for additional increases in production, reserves and cash flow. However, our ability to achieve such increases could be adversely affected by future decreases in the demand for crude oil and natural gas, impediments in marketing production, operating risks, unavailability of capital, adverse changes in governmental regulations or other currently unforeseen developments. Accordingly, we can give no assurance that such increases will be achieved. We believe that attractive acquisition opportunities that fit our criteria will continue to be made available by both major and independent oil companies. In addition to more typical acquisitions, we also intend to pursue joint ventures and strategic alliances that provide us the opportunity to use our exploitation and operating skillsets and our capital without acquiring the entire property interest. While we are continually evaluating such opportunities, there can be no assurance that any of these efforts will be successful. Our ability to continue to acquire attractive properties may be adversely affected by: . a reduction in the number of attractive properties offered for sale; . increased competition for properties from other independent oil companies; . unavailability of capital; . incorrect estimates of reserves; . exploitation potential or environmental liabilities or other factors. Although we have historically acquired producing properties located only in the continental United States, from time to time we evaluate, and may in the future seek to acquire, properties located outside the continental United States. DISPOSITION OF PROPERTIES We periodically evaluate, and from time to time have elected to sell, certain of our mature producing properties that we consider to be nonstrategic or fully valued. Such sales enable us to focus on our core properties, maintain financial flexibility, reduce overhead and redeploy the proceeds therefrom to activities that we believe have a higher potential financial return. We have not made any material sales of our producing properties during our last three fiscal years. MIDSTREAM ACTIVITIES GENERAL We conduct our midstream activities through PAA, which was formed in 1998 to acquire and operate the business and assets of our wholly owned midstream subsidiaries. PAA engages in interstate and intrastate crude oil transportation, terminalling and storage, as well as crude oil gathering and marketing activities. In 1999, PAA grew through acquisitions and internal development to become one of the largest transporters, terminal operators, gatherers and marketers of crude oil in the United States. At the beginning of 2000, PAA handled an average of approximately 650,000 barrels of crude oil per day. Its operations are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. 9 Our midstream business strategy is to capitalize on the regional crude oil supply and demand imbalances that exist in the continental United States by combining the strategic location and unique capabilities of our transportation and terminalling assets with our extensive marketing and distribution expertise to generate sustainable earnings and cash flow. We intend to execute our midstream business strategy by: . increasing and optimizing the amount of crude oil we transport on our various pipeline and gathering assets; . realizing cost efficiencies through operational improvements and potential strategic alliances; . utilizing our Cushing Terminal and other assets to service the needs of refiners and to profit from merchant activities that take advantage of crude oil pricing and quality differentials; and . pursuing strategic and accretive acquisitions of crude oil pipeline assets, gathering systems and terminalling and storage facilities that complement our existing asset base and distribution capabilities. Our midstream line of business consists of: . gathering crude oil from the fields where the crude oil is produced; . interstate and intrastate transportation of crude oil through pipelines, trucks or barges; . storing crude oil in our storage tanks; . transferring crude oil from pipelines and storage tanks to trucks, barges or other pipelines through our terminals; . marketing crude oil produced by Plains Resources; . the purchase of crude oil at the well and the bulk purchase of crude oil at pipeline and terminal facilities; and . the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain. The principal assets used in this segment include: . a 3.1 million barrel, above-ground crude oil storage and terminal facility at Cushing, Oklahoma; . the segment of the All American Pipeline that extends approximately 140 miles from Las Flores, California to Emidio, California; . the San Joaquin Valley Gathering System in California; . the West Texas Gathering System, the Spraberry Pipeline System, and the East Texas Pipeline System, which are all located in Texas; . the Sabine Pass Pipeline System in southwest Louisiana and southeast Texas; . the Ferriday Pipeline System in eastern Louisiana and western Mississippi; . the Illinois Basin Pipeline System in southern Illinois; and . approximately 280 trucks, 325 tractor-trailers and 290 injection stations, which are owned or leased and used in our gathering and marketing activities. MIDSTREAM ACQUISITIONS AND DISPOSITIONS Scurlock Acquisition On May 12, 1999, we completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, is engaged in crude oil transportation, gathering and marketing, and owns approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil linefill. 10 Financing for the Scurlock acquisition was provided through: . borrowings of approximately $92.0 million under Plains Scurlock's limited recourse bank facility with BankBoston, N.A.; . the sale to the general partner of 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of PAA's common units on May 12, 1999; and . a $25.0 million draw under PAA's existing revolving credit agreement. The funds for the purchase of the Class B Units by the general partner were provided by a capital contribution from us. We financed our capital contribution through our revolving credit facility. The Class B units are initially pari passu with common units with respect to distributions, and are convertible into common units upon approval of a majority of the common unitholders. The Class B unitholders may request that PAA call a meeting of common unitholders to consider approval of the conversion of Class B units into common units. If the approval of a conversion by the common unitholders is not obtained within 120 days of a request, each Class B unitholder will be entitled to receive distributions, on a per unit basis, equal to 110% of the amount of distributions paid on a common unit, with such distribution right increasing to 115% if such approval is not secured within 90 days after the end of the 120-day period. Except for the vote to approve the conversion, Class B units have the same voting rights as the common units. West Texas Gathering System Acquisition On July 15, 1999, we completed the acquisition of the West Texas Gathering System from Chevron Pipe Line Company for approximately $36.0 million. Financing for the amounts paid at closing was provided by a draw under the term loan portion of the Plains Scurlock credit facility. The assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines, and approximately 2.9 million barrels of tankage located along the system. All American Pipeline Linefill Sale and Asset Disposition 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 substantially completed in February 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 the Goodyear Tire & Rubber Company in July 1998. Proceeds from the sale of the linefill were approximately $100 million, net of associated costs, and were used for working capital purposes. We estimate that we will recognize a total gain of approximately $44.6 million in connection with the sale of linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. 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 total proceeds of $129.0 million. The proceeds from the sale were used to reduce outstanding debt. Our net proceeds are expected to be approximately $124.0 million, net of associated transaction costs and estimated costs to remove certain equipment. We estimate that we will recognize a gain of approximately $20.0 million in connection with the sale. During 1999, we reported gross margin of approximately $5.0 million from volumes transported on the segment of the line that was sold. CRUDE OIL PIPELINE OPERATIONS We present below a description of our principal pipeline assets. All of our pipeline systems are operated from one of two central control rooms with computer systems designed to continuously monitor real time operational data including measurement of crude oil quantities injected in and delivered through the pipelines, product flow rates and pressure and temperature variations. This monitoring and measurement technology provides us the ability to efficiently batch differing crude oil types with varying characteristics through the pipeline systems. The systems are designed to enhance leak detection capabilities, sound automatic alarms in the event of operational conditions outside of pre-established parameters and provide for remote-controlled shut- down of pump stations on the pipeline systems. Pump stations, storage facilities and meter measurement points along the pipeline systems are linked by telephone, microwave, satellite or radio communication systems for remote monitoring and control, which reduces our requirement for full time site personnel at most of these locations. 11 We perform scheduled maintenance on all of our pipeline systems and make repairs and replacements when necessary or appropriate. We attempt to control corrosion of the mainlines through the use of corrosion inhibiting chemicals injected into the crude stream, external coatings and anode bed based or impressed current cathodic protection systems. Maintenance facilities containing equipment for pipe repairs, spare parts and trained response personnel are strategically located along the pipelines and in concentrated operating areas. We believe that all of our pipelines have been constructed and are maintained in all material respects in accordance with applicable federal, state and local laws and regulations, standards prescribed by the American Petroleum Institute and accepted industry practice. All American Pipeline The segment of the All American Pipeline that was not sold to El Paso (see " - All American Pipeline Linefill Sale and Asset Disposition") is a common carrier crude oil pipeline system that transports crude oil produced from fields offshore and onshore California to locations in California pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC") (see " - Regulation - Transportation of Crude Oil"). As a common carrier, the All American Pipeline offers transportation services to any shipper of crude oil, provided that the crude oil tendered for transportation satisfies the conditions and specifications contained in the applicable tariff. The All American Pipeline transports crude oil for third parties as well as for us. We currently operate the segment of the system that extends approximately 10 miles from Exxon's onshore facilities at Las Flores on the California coast to our onshore facilities at Gaviota, California (24 inch diameter pipe) and continues from Gaviota approximately 130 miles to our station in Emidio, California (30-inch pipe). Between Gaviota and our Emidio Station, the All American Pipeline interconnects with our SJV Gathering System as well as various third party intrastate pipelines, including the Unocap Pipeline System, Pacific Pipeline, and a pipeline owned by EOTT Energy Partners, L.P. System Supply. The All American Pipeline currently transports Outer Continental Shelf crude oil received at the onshore facilities of the Santa Ynez field at Las Flores, California and the onshore facilities of the Point Arguello field located at Gaviota, California. Effective December 1, 1999, the segment of the All American Pipeline that was sold to El Paso ceased being used for crude oil transportation. Exxon, which owns all of the Santa Ynez production, Texaco and Sun Operating L.P., which together own approximately 25% of the Point Arguello production, have entered into transportation agreements committing to transport all of their production from these fields on the segment of the All American Pipeline which we retained. These agreements, which expire in August 2007, provide for a minimum tariff with annual escalations. At December 31, 1999, the tariffs averaged $1.41 per barrel for deliveries to connecting pipelines in California. The agreements do not require these owners to transport a minimum volume. The producers from the Point Arguello field who do not have contracts with us have no other means of transporting their production and, therefore, ship their volumes on the All American Pipeline at the posted tariffs. For the year ended December 31, 1999, approximately $30.6 million, or 17%, of our gross margin was attributable to the Santa Ynez field and approximately $10.6 million, or 6% was attributable to the Point Arguello field. Transportation of volumes from the Point Arguello field on the All American Pipeline commenced in 1991 and from the Santa Ynez field in 1994. The table below sets forth the historical volumes received from both of these fields.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------- 1999 1998 1997 1996 1995 1994 1993 1992 1991 -------- ------- ------- -------- --------- -------- -------- ------- ------- (BARRELS IN THOUSANDS) Average daily volumes received from: Point Arguello (at Gaviota) 20 26 30 41 60 73 63 47 29 Santa Ynez (at Las Flores) 59 68 85 95 92 34 - - - ------- ------ ------ ------- ------- ------ ------ ------ ------- Total 79 94 115 136 152 107 63 47 29 ======= ====== ====== ======= ======= ====== ====== ====== =======
In July 1999, a wholly-owned subsidiary of ours acquired Chevron USA's 26% working interest in Point Arguello and is the operator of record for the Point Arguello Unit. All of the volumes attributable to our interests are committed for transportation on the All American Pipeline and are subject to our Marketing Agreement with PAA. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. As operator of Point Arguello, we are conducting additional drilling and other activities on this field, but we can not assure you that these activities will affect the production decline. 12 San Joaquin Valley Supply. The San Joaquin Valley is one of the most prolific oil producing regions in the continental United States, producing approximately 559,000 barrels per day of crude oil during the first nine months of 1999 that accounted for approximately 67% of total California production and 11% of the total production in the lower 48 states. The following table reflects the historical production for the San Joaquin Valley as well as total California production (excluding OCS volumes) as reported by the California Division of Oil and Gas.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------------------------ 1999 (1) 1998 1997 1996 1995 1994 1993 1992 1991 1990 ---------- ------ -------- -------- -------- -------- -------- -------- ------- ------- (BARRELS IN THOUSANDS) Average daily volumes: San Joaquin Valley production (2) 559 592 584 579 569 578 588 609 634 629 Total California production (excluding OCS volumes) 731 781 781 772 764 784 803 835 875 879
- ----------- (1) Reflects information through September 1999. (2) Consists of production from California Division of Oil and Gas District IV. System Demand. Deliveries from the All American Pipeline are made to California refineries through connections with third-party pipelines at Sisquoc, Pentland and Emidio. Deliveries at Mojave were discontinued in the second quarter of 1999, and volumes previously delivered to Mojave are delivered to Emidio. Except for the purging of the linefill volumes, deliveries to Texas were discontinued effective December 1, 1999. 13 The following table sets forth All American Pipeline average deliveries per day within and outside California.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------- 1999 1998 1997 1996 1995 ------------- ----------- ----------- ----------- ----------- (BARRELS IN THOUSANDS) Average daily volumes delivered to: California Sisquoc 27 24 21 17 11 Pentland 52 69 74 71 65 Mojave 7 22 32 6 - Emidio 15 - - - - ------------- ----------- ----------- ----------- ----------- Total California 101 115 127 94 76 Texas (1) 56 59 68 113 141 ------------- ----------- ----------- ----------- ----------- Total 157 174 195 207 217 ============= =========== =========== =========== ===========
- --------- (1) See " Midstream Acquisitions and Dispositions - All American Linefill and Asset Disposition". SJV Gathering System The SJV Gathering System is a proprietary pipeline system. As a proprietary pipeline, the SJV Gathering System is not subject to common carrier regulations. The SJV Gathering System was constructed in 1987 with a design capacity of approximately 140,000 barrels per day. The system consists of a 16-inch pipeline that originates at the Belridge station and extends 45 miles south to a connection with the All American Pipeline at the Pentland station. The SJV Gathering System is connected to several fields, including the South Belridge, Elk Hills and Midway Sunset fields, three of the seven largest producing fields in the lower 48 states. In 1999, we leased a pipeline that provides us access to the Lost Hills field. The SJV Gathering System also includes approximately 586,000 barrels of tank capacity, which can be used to facilitate movements along the system as well as to support our other activities. The SJV Gathering System is supplied with the crude oil production primarily from major oil companies' equity production from the South Belridge, Cymeric, Midway Sunset, Elk Hills and Lost Hills fields. The table below sets forth the historical volumes received into the SJV Gathering System.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------- 1999 1998 1997 1996 1995 ------------- --------- --------- --------- --------- (BARRELS IN THOUSANDS) Total average daily volumes 84 85 91 67 50
West Texas Gathering System We purchased the West Texas Gathering System from Chevron Pipe Line Company in July 1999 for approximately $36.0 million. The West Texas Gathering System is a common carrier crude oil pipeline system located in the heart of the Permian Basin producing area. The West Texas Gathering System has lease gathering facilities in Crane, Ector, Upton, Ward and Winkler counties. In aggregate, these counties have produced on average in excess of 150,000 barrels per day of crude oil over the last four years. The West Texas Gathering System was originally built by Gulf Oil Corporation in the late 1920's, expanded during the late 1950's and updated during the mid 1990's. The West Texas Gathering System provides us with considerable flexibility, as major segments are bi-directional and allow us to move crude oil between three of the major trading locations in West Texas. Lease volumes gathered into the system are approximately 50,000 barrels per day. Chevron USA has agreed to transport its equity crude oil production from fields connected to the West Texas Gathering System on the system through July 2011 (currently representing approximately 22,000 barrels per day, or 44% of total system gathering volumes and 22% of the total system volumes). Other large producers connected to the gathering system include Burlington, Devon, Anadarko, Altura, Bass, and Fina. Volumes from connecting carriers, including Exxon, Phillips and Unocal, average approximately 42,000 barrels per day. Our West Texas Gathering System has the capability to transport approximately 190,000 barrels per day. At the time of the acquisition, truck injection stations were limited and provided less than 1,000 barrels per day. We have installed ten truck injection stations on the West Texas Gathering System since the acquisition. Our trucks are used to pick up crude oil produced in the areas adjacent to the West Texas Gathering System and deliver these volumes into the pipeline. These additional injection stations allowed us to reduce the distance of our truck hauls in this area, increase the utilization of 14 our pipeline assets and reduce our operating costs. Volumes received from truck injection stations were increased to 10,000 barrels per day by the fourth quarter of 1999. The West Texas Gathering System also includes approximately 2.9 million barrels of tank capacity located along the pipeline system. Spraberry Pipeline System The Spraberry Pipeline System, acquired in the Scurlock acquisition, is a proprietary pipeline system that gathers crude oil from the Spraberry Trend of West Texas and transports it to Midland, Texas, where it interconnects with the West Texas Gathering System and other pipelines. The Spraberry Pipeline System consists of approximately 800 miles of pipe of varying diameter, and has a throughput capacity of approximately 50,000 barrels of crude oil per day. The Spraberry Trend is one of the largest producing areas in West Texas, and we are one of the largest gatherers in the Spraberry Trend. The Spraberry Pipeline System gathers approximately 34,000 barrels per day of crude oil. Large suppliers to the Spraberry Pipeline System include Lantern Petroleum and Pioneer Natural Resources. The Spraberry Pipeline System also includes approximately 173,000 barrels of tank capacity located along the pipeline. Sabine Pass Pipeline System The Sabine Pass Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system. The primary purpose of the Sabine Pass Pipeline System is to gather crude oil from onshore facilities of offshore production near Johnson's Bayou, Louisiana, and deliver it to tankage and barge loading facilities in Sabine Pass, Texas. The Sabine Pass Pipeline System consists of approximately 34 miles of pipe ranging from 4 to 6 inches in diameter and has a throughput capacity of approximately 26,000 barrels of Louisiana light sweet crude oil per day. For the year ended December 31, 1999, the system transported approximately 16,500 barrels of crude oil per day. The Sabine Pass Pipeline System also includes 245,000 barrels of tank capacity located along the pipeline. Ferriday Pipeline System The Ferriday Pipeline System, acquired in the Scurlock acquisition, is a common carrier crude oil pipeline system which is located in East Louisiana and West Mississippi. The Ferriday Pipeline System consists of approximately 600 miles of pipe ranging from 2 inches to 12 inches in diameter. The Ferriday Pipeline System delivers 9,000 barrels per day of crude oil to third-party pipelines that supply refiners in the Midwest. The Ferriday Pipeline System also includes approximately 348,000 barrels of tank capacity located along the pipeline. In November 1999, we completed the construction of an 8-inch pipeline underneath the Mississippi River that connects our Ferriday Pipeline System in West Mississippi with the portion of the system located in East Louisiana. This connection provides us with bi-directional capability to access additional markets and enhances our ability to service our pipeline customers and take advantage of additional high margin merchant activities. East Texas Pipeline System The East Texas Pipeline System, acquired in the Scurlock acquisition, is a proprietary crude oil pipeline system that is used to gather approximately 10,000 barrels per day of crude oil in East Texas and transport approximately 22,000 barrels per day of crude oil to Crown Central's refinery in Longview, Texas. The deliveries to Crown Central are subject to a five-year throughput and deficiency agreement, which extends through 2004. The East Texas Pipeline System also includes approximately 221,000 barrels of tank capacity located along the pipeline. Illinois Basin Pipeline System The Illinois Basin Pipeline System, acquired in the Scurlock acquisition, consists of common carrier pipeline and gathering systems and truck injection facilities in southern Illinois. The Illinois Basin Pipeline System consists of approximately 170 miles of pipe of varying diameter and delivers approximately 6,400 barrels per day of crude oil to third-party pipelines that supply refiners in the Midwest. During 1999, approximately 3,600 barrels per day of the supply on this system are from fields operated by us. 15 TERMINALLING AND STORAGE ACTIVITIES AND GATHERING AND MARKETING ACTIVITIES Terminalling and Storage Activities We own approximately 9.7 million barrels of terminalling and storage assets, including tankage associated with our pipeline and gathering systems. Our storage and terminal operations increase our margins in our business of purchasing and selling crude oil and also generate revenue through a combination of storage and throughput charges to third parties. Storage fees are generated when we lease tank capacity to third parties. Terminalling fees, also referred to as throughput fees, are generated when we receive crude oil from one connecting pipeline and redeliver such crude oil to another connecting carrier in volumes that allow the refinery to receive its crude oil on a ratable basis throughout a delivery period. Both terminalling and storage fees are generally earned from: . refiners and gatherers that segregate or custom blend crudes for refining feedstocks; . pipeline operators, refiners or traders that need segregated tankage for foreign cargoes; . traders who make or take delivery under NYMEX contracts; and . producers and resellers that seek to increase their marketing alternatives. The tankage that is used to support our arbitrage activities positions us to capture margins in a contango market or when the market switches from contango to backwardation. Our most significant terminalling and storage asset is our Cushing Terminal which was constructed in 1993, and expanded by approximately 50% in 1999, to capitalize on the crude oil supply and demand imbalance in the Midwest. The imbalance was caused by the continued decline of regional production supplies, increasing imports and an inadequate pipeline and terminal infrastructure. The Cushing Terminal is also used to support and enhance the margins associated with our merchant activities relating to our lease gathering and bulk trading activities. The Cushing Terminal has total storage capacity of approximately 3.1 million barrels. The Cushing Terminal is comprised of fourteen 100,000 barrel tanks, four 150,000 barrel tanks and four 270,000 barrel tanks which are used to store and terminal crude oil. The Cushing Terminal also includes a pipeline manifold and pumping system that has an estimated daily throughput capacity of approximately 800,000 barrels per day. The pipeline manifold and pumping system is designed to support more than ten million barrels of tank capacity. The Cushing Terminal is connected to the major pipelines and terminals in the Cushing Interchange through pipelines that range in size from 10 inches to 24 inches in diameter. The Cushing Terminal is a state-of-the-art facility designed to serve the needs of refiners in the Midwest. In order to service an expected increase in the volumes as well as the varieties of foreign and domestic crude oil projected to be transported through the Cushing Interchange, we incorporated certain attributes into the design of the Cushing Terminal including: . multiple, smaller tanks to facilitate simultaneous handling of multiple crude varieties in accordance with normal pipeline batch sizes; . dual header systems connecting each tank to the main manifold system to facilitate efficient switching between crude grades with minimal contamination; . bottom drawn sumps that enable each tank to be efficiently drained down to minimal remaining volumes to minimize crude contamination and maintain crude integrity during changes of service; . mixer(s) on each tank to facilitate blending crude grades to refinery specifications; and . a manifold and pump system that allows for receipts and deliveries with connecting carriers at their maximum operating capacity. As a result of incorporating these attributes into the design of the Cushing Terminal, we believe we are favorably positioned to serve the needs of Midwest refiners to handle an increase in varieties of crude transported through the Cushing Interchange. The Cushing Terminal also incorporates numerous environmental and operational safeguards. We believe that our terminal is the only one at the Cushing Interchange in which each tank has a secondary liner (the equivalent of double bottoms), leak detection devices and secondary seals. The Cushing Terminal is the only terminal at the Cushing Interchange equipped with aboveground pipelines. Like the pipeline systems we operate, the Cushing Terminal is operated by a computer system designed to continuously monitor real time operational data and each tank is cathodically protected. In addition, each tank is equipped with an audible and visual high level alarm system to prevent overflows; a double seal floating roof that minimizes air emissions and prevents the possible accumulation 16 of potentially flammable gases between fluid levels and the roof of the tank; and a foam dispersal system that, in the event of a fire, is fed by a fully- automated fire water distribution network. The Cushing Interchange is the largest wet barrel trading hub in the U.S. and the delivery point for crude oil futures contracts traded on the NYMEX. The Cushing Terminal has been designated by the NYMEX as an approved delivery location for crude oil delivered under the NYMEX light sweet crude oil futures contract. As the NYMEX delivery point and a cash market hub, the Cushing Interchange serves as a primary source of refinery feedstock for the Midwest refiners and plays an integral role in establishing and maintaining markets for many varieties of foreign and domestic crude oil. The following table sets forth throughput volumes for our terminalling and storage operations, and quantity of tankage leased to third parties from 1995 through 1999.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------- 1999 1998 1997 1996 1995 ----------- ----------- ---------- ---------- --------- (BARRELS IN THOUSANDS) Throughput volumes (average daily volumes): Cushing Terminal 72 69 69 56 43 Ingleside Terminal 11 11 8 3 - ----------- ------- -------- ------- -------- Total 83 80 77 59 43 =========== ======= ======== ======= ======== Storage leased to third parties (monthly average volumes): Cushing Terminal 1,743 890 414 203 208 Ingleside Terminal 232 260 254 211 - ----------- ------- -------- ------- -------- Total 1,975 1,150 668 414 208 =========== ======= ======== ======= ========
Gathering and Marketing Activities Our gathering and marketing activities are conducted in 23 states; however, the vast majority of those activities are in Texas, Louisiana, California, Illinois and the Gulf of Mexico. These activities include: . purchasing crude oil from producers at the wellhead and in bulk from aggregators at major pipeline interconnects and trading locations; . transporting this crude oil on our own proprietary gathering assets or assets owned and operated by third parties when necessary or cost effective; . exchanging this crude oil for another grade of crude oil or at a different geographic location, as appropriate, in order to maximize margins or meet contract delivery requirements; and . marketing crude oil to refiners or other resellers. We purchase crude oil from many independent producers and believe that we have established broad-based relationships with crude oil producers in our areas of operations. For the year ended December 31, 1999, we purchased approximately 265,000 barrels per day of crude oil directly at the wellhead from more than 2,200 producers from approximately 10,700 leases. We purchase crude oil from producers under contracts that range in term from a thirty-day evergreen to three years. Gathering and marketing activities are characterized by large volumes of transactions with lower margins relative to pipeline and terminalling and storage operations. In the period immediately following the disclosure of the unauthorized trading losses, a significant number of PAA's suppliers and trading partners reduced or eliminated the open credit previously extended to PAA. Consequently, the amount of letters of credit PAA needed to support the level its crude oil purchases then in effect increased significantly. In many instances PAA arranged for letters of credit to secure its obligations to purchase crude oil from its customers. In other instances, certain of PAA's purchase contracts were terminated. As a result of these changes, aggregate volumes purchased are expected to decrease by 150,000 barrels per day, consisting primarily of lower unit margin purchases. Approximately 50,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 100,000 barrels per day is attributable to bulk purchases. See "Unauthorized Trading Losses". 17 The following table shows the average daily volume of our lease gathering and bulk purchases from 1995 through 1999.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------------ 1999 (1) 1998 1997 1996 1995 ------------- ----------- ----------- ----------- ----------- (BARRELS IN THOUSANDS) Lease gathering 239 88 71 59 46 Bulk purchases 138 98 49 32 10 --- --- --- -- -- Total volumes 377 186 120 91 56 === === === == ==
- ---------------- (1) Includes volumes from Scurlock Permian since May 1, 1999. Crude Oil Purchases. In a typical producer's operation, crude oil flows from the wellhead to a separator where the petroleum gases are removed. After separation, the crude oil is treated to remove water, sand and other contaminants and is then moved into the producer's on-site storage tanks. When the tank is full, the producer contacts our field personnel to purchase and transport the crude oil to market. We utilize our truck fleet and gathering pipelines and third-party pipelines, trucks and barges to transport the crude oil to market. We own or lease approximately 280 trucks, 325 tractor-trailers and 290 injection stations. We have a Marketing Agreement with PAA, under which they are the exclusive marketer/purchaser for all of our equity crude oil production. The Marketing Agreement provides that they will purchase for resale at market prices all of our crude oil production for which they charge a fee of $0.20 per barrel. This fee will be adjusted every three years based upon then existing market conditions. The Marketing Agreement will terminate upon a "change of control" of us or the general partner. Bulk Purchases. In addition to purchasing crude oil at the wellhead from producers, we purchase crude oil in bulk at major pipeline terminal points. This production is transported from the wellhead to the pipeline by major oil companies, large independent producers or other gathering and marketing companies. We purchase crude oil in bulk when we believe additional opportunities exist to realize margins further downstream in the crude oil distribution chain. The opportunities to earn additional margins vary over time with changing market conditions. Accordingly, the margins associated with our bulk purchases will fluctuate from period to period. Our bulk purchasing activities are concentrated in California, Texas, Louisiana and at the Cushing Interchange. Crude Oil Sales. The marketing of crude oil is complex and requires detailed current knowledge of crude oil sources and end markets and a familiarity with a number of factors including grades of crude oil, individual refinery demand for specific grades of crude oil, area market price structures for the different grades of crude oil, location of customers, availability of transportation facilities and timing and costs (including storage) involved in delivering crude oil to the appropriate customer. We sell our crude oil to major integrated oil companies, independent refiners and other resellers in various types of sale and exchange transactions, at market prices for terms ranging from one month to three years. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users, such as independent refiners or major oil companies, or by entering into a future delivery obligation with respect to futures contracts on the NYMEX. Through these transactions, we seek to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. We from time to time enter into fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil futures contracts as hedging devices. Our policy is generally to purchase only crude oil for which we have a market and to structure our sales contracts so that crude oil price fluctuations do not materially affect the gross margin which we receive. We do not acquire and hold crude oil, futures contracts or other derivative products for the purpose of speculating on crude oil price changes that might expose us to indeterminable losses. In November 1999, we discovered that this policy was violated and we incurred $174.0 million in unauthorized trading losses, including estimated associated costs and legal expenses. See "Unauthorized Trading Losses". Risk management strategies, including those involving price hedges using NYMEX futures contracts, have become increasingly important in creating and maintaining margins. Such hedging techniques require significant resources dedicated to managing futures positions. We are able to monitor crude oil volumes, grades, locations and delivery schedules and to coordinate marketing and exchange opportunities, as well as NYMEX hedging positions. This coordination ensures that our NYMEX hedging activities are successfully implemented. We have recently hired a Risk Manager that has direct responsibility and authority for our risk policies and our trading controls and procedures and other aspects of corporate risk management. 18 Crude Oil Exchanges. We pursue exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase our margin or to acquire a grade of crude oil that more nearly matches our delivery requirement or the preferences of our refinery customers, we exchange physical crude oil with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, we agree to buy crude oil that differs in terms of geographic location, grade of crude oil or delivery schedule from crude oil we have available for sale. Generally, we enter into exchanges to acquire crude oil at locations that are closer to our end markets, thereby reducing transportation costs and increasing our margin. We also exchange our crude oil to be delivered at an earlier or later date, if the exchange is expected to result in a higher margin net of storage costs, and enter into exchanges based on the grade of crude oil, which includes such factors as sulfur content and specific gravity, in order to meet the quality specifications of our delivery contracts. Producer Services. Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. Through our team of crude oil purchasing representatives, we maintain ongoing relationships with more than 2,200 producers. We believe that our ability to offer high-quality field and administrative services to producers is a key factor in our ability to maintain volumes of purchased crude oil and to obtain new volumes. High-quality field services include efficient gathering capabilities, availability of trucks, willingness to construct gathering pipelines where economically justified, timely pickup of crude oil from tank batteries at the lease or production point, accurate measurement of crude oil volumes received, avoidance of spills and effective management of pipeline deliveries. Accounting and other administrative services include securing division orders (statements from interest owners affirming the division of ownership in crude oil purchased by us), providing statements of the crude oil purchased each month, disbursing production proceeds to interest owners and calculation and payment of ad valorem and production taxes on behalf of interest owners. In order to compete effectively, we must maintain records of title and division order interests in an accurate and timely manner for purposes of making prompt and correct payment of crude oil production proceeds, together with the correct payment of all severance and production taxes associated with such proceeds. Credit. Our merchant activities involve the purchase of crude oil for resale and require significant extensions of credit by our suppliers of crude oil. In order to assure our ability to perform our obligations under crude oil purchase agreements, various credit arrangements are negotiated with our crude oil suppliers. Such arrangements include open lines of credit directly with us and standby letters of credit issued under our letter of credit facility. Due to the unauthorized trading losses, the amount of letters of credit that we are required to provide to secure our crude oil purchases has increased. See "Unauthorized Trading Losses". When we market crude oil, we must determine the amount, if any, of the line of credit to be extended to any given customer. If we determine that a customer should receive a credit line, we must then decide on the amount of credit that should be extended. Since our typical sales transactions can involve tens of thousands of barrels of crude oil, the risk of nonpayment and nonperformance by customers is a major consideration in our business. We believe our sales are made to creditworthy entities or entities with adequate credit support. Credit review and analysis are also integral to our leasehold purchases. Payment for all or substantially all of the monthly leasehold production is sometimes made to the operator of the lease. The operator, in turn, is responsible for the correct payment and distribution of such production proceeds to the proper parties. In these situations, we must determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend us in the event any third party should bring a protest, action or complaint in connection with the ultimate distribution of production proceeds by the operator. OPERATING ACTIVITIES See Note 22 in the notes to our consolidated financial statements located elsewhere in this report for information with respect to the operating activities of our upstream and midstream segments. PRODUCT MARKETS AND MAJOR CUSTOMERS Our revenues are highly dependent upon the prices of, and demand for, crude oil and natural gas. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices we receive for our crude oil and natural gas production and the levels of such production are subject to wide fluctuations and depend on numerous factors beyond our control, including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, 19 legislation and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. The benchmark NYMEX crude oil price of $25.60 per barrel at December 31, 1999 was more than double the $12.05 per barrel at the end of 1998. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations -- "Outlook". In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, from time to time we purchase put options, enter into fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, we may sell a futures contract and thereafter either (1) make physical delivery of our product to comply with such contract or (2) buy a matching futures contract to unwind our futures position and sell our production to a customer. These same techniques are also utilized to manage price risk for certain production purchased from customers of PAA. Such contracts may expose us to the risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase or deliver the contracted quantities of crude oil or natural gas, or a sudden, unexpected event materially impacts crude oil or natural gas prices. Such contracts may also restrict our ability to benefit from unexpected increases in crude oil and natural gas prices. See Item 2. -- "Properties -- Crude Oil and Natural Gas Reserves". Substantially all of our California crude oil and natural gas production and our Sunniland Trend oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our crude oil and natural gas production. Certain of our natural gas production has been in the past, and may be in the future, curtailed from time to time depending on the quality of the natural gas produced and transportation alternatives. In addition, market, economic and regulatory factors, including issues regarding the quality of certain of our natural gas, may in the future adversely affect our ability to sell our natural gas production. Deregulation of natural gas prices has increased competition and volatility of natural gas prices. Since demand for natural gas is generally highest during winter months, prices received for our natural gas are subject to seasonal variations and other fluctuations. All of our natural gas production is currently sold under various arrangements at spot indexed prices. In certain instances we enter into financial arrangements to hedge our exposure to spot price fluctuations. See Item 2. -- "Properties -- Production and Sales" and Item 7. -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook". Customers accounting for more than 10% of total sales for the periods indicated are as follows:
PERCENTAGE OF TOTAL SALES -------------------------------------------------------- YEAR ENDED DECEMBER 31, -------------------------------------------------------- Customer 1999 1998 1997 -------------------------------------------------------- Sempra Energy Trading Corporation 22% 27% 11% Koch Oil Company 18% 15% 27% PERCENTAGE OF OIL AND GAS SALES (1) -------------------------------------------------------- Chevron 43% - - Tosco Refining Company 21% 50% - Conoco Inc. 12% - - Scurlock Permian LLC - 17% - Unocal Energy Trading, Inc. - - 52% Marathon Oil Company 17% - 23% Exxon Company U.S.A. - - 10%
- ---------------- (1) PAA is the exclusive marketer/purchaser for all our equity crude oil production. These percentages represent the entities that purchased our equity crude production from PAA. We believe that the loss of an individual customer would not have a material adverse effect. 20 Competition Crude Oil and Natural Gas Producing Activities Our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than those available to us. Such companies are able to pay more for productive crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Midstream Activities Competition among pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. We believe that high capital requirements, environmental considerations and the difficulty in acquiring rights of way and related permits make it unlikely that competing pipeline systems comparable in size and scope to our pipeline systems will be built in the foreseeable future. We face intense competition in our terminalling and storage activities and gathering and marketing activities. Our competitors include other crude oil pipelines, the major integrated oil companies, their marketing affiliates and independent gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil. REGULATION Our operations are subject to extensive regulation. Many departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil industry increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these regulations than are our competitors. Due to the myriad of complex federal and state statutes and regulations which may affect us, directly or indirectly, you should not rely on the following discussion of certain statutes and regulations as an exhaustive review of all regulatory considerations affecting our operations. OSHA We are also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Trucking Regulation We operate a fleet of trucks to transport crude oil and oilfield materials as a private, contract and common carrier. We are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the Department of Transportation. The trucking regulations cover, among other things, driver operations, keeping of log books, truck manifest preparations, the placement of safety placards on the trucks and trailer vehicles, drug and alcohol testing, safety of operation and equipment, and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations. Pipeline Regulation Our pipelines are subject to regulation by the Department of Transportation under the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA") relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA requires us and other pipeline operators to comply with regulations issued 21 pursuant to HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. The Pipeline Safety Act of 1992 amends the HLPSA in several important respects. It requires the Research and Special Programs Administration of the Department of Transportation to consider environmental impacts, as well as its traditional public safety mandate, when developing pipeline safety regulations. In addition, the Pipeline Safety Act mandates the establishment by the Department of Transportation of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to the Research and Special Programs Administration. It also authorizes the Research and Special Programs Administration to require that pipelines be modified to accommodate internal inspection devices, to mandate the installation of emergency flow restricting devices for pipelines in populated or sensitive areas and to order other changes to the operation and maintenance of petroleum pipelines. We believe that our pipeline operations are in substantial compliance with applicable HLPSA and Pipeline Safety Act requirements. Nevertheless, we could incur significant expenses in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities. States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate. Transportation of Crude Oil General Interstate Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by the FERC under the Interstate Commerce Act. The Interstate Commerce Act requires that tariff rates for petroleum pipelines, which includes crude oil, as well as refined product and petrochemical pipelines, be just and reasonable and non-discriminatory. The Interstate Commerce Act permits challenges to proposed new or changed rates by protest, and challenges to rates that are already final and in effect by complaint. Upon the appropriate showing, a successful complainant may obtain reparations for overcharges sustained for a period of up to two years prior to the filing of a complaint. The FERC is authorized to suspend the effectiveness of a new or changed tariff rate for a period of up to seven months and to investigate the rate. If upon the completion of an investigation the FERC finds that the rate is unlawful, it may require the pipeline operator to refund to shippers, with interest, any difference between the rates the FERC determines to be lawful and the rates under investigation. In addition, the FERC will order the pipeline to change its rates prospectively to the lawful level. In general, petroleum pipeline rates must be cost-based, although settlement rates, which are rates that have been agreed to by all shippers, are permitted, and market-based rates may be permitted in certain circumstances. Under a cost- of-service basis, rates are permitted to generate operating revenues, on the basis of projected volumes, not greater than the total of the following: . operating expenses; . depreciation and amortization; . federal and state income taxes; and . an overall allowed rate of return on the pipeline's "rate base." Energy Policy Act of 1992 and Subsequent Developments. In October 1992 Congress passed the Energy Policy Act of 1992. The Energy Policy Act deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the Energy Policy Act or that were in effect on the 365th day preceding enactment and had not been subject to complaint, protest or investigation during the 365-day period to be just and reasonable under the Interstate Commerce Act. The Energy Policy Act also provides that complaints against such rates may only be filed under the following limited circumstances: . a substantial change has occurred since enactment in either the economic circumstances or the nature of the services which were a basis for the rate; . the complainant was contractually barred from challenging the rate prior to enactment; or . a provision of the tariff is unduly discriminatory or preferential. 22 The Energy Policy Act further required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines, and to streamline procedures in petroleum pipeline proceedings. On October 22, 1993, the FERC responded to the Energy Policy Act directive by issuing Order No. 561, which adopts a new indexing rate methodology for petroleum pipelines. Under the new regulations, which were effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods, minus one percent. Rate increases made pursuant to the index will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. The new indexing methodology can be applied to any existing rate, even if the rate is under investigation. If such rate is subsequently adjusted, the ceiling level established under the index must be likewise adjusted. In Order No. 561, the FERC said that as a general rule pipelines must utilize the indexing methodology to change their rates. The FERC indicated, however, that it was retaining cost-of-service ratemaking, market-based rates, and settlements as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above index levels for uncontrollable circumstances. A pipeline can seek to charge market- based rates if it can establish that it lacks market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. Initial rates for new services can be established through a cost-of- service proceeding or through an uncontested agreement between the pipeline and all of its shippers, including at least one shipper not affiliated with the pipeline. On May 10, 1996, the Court of Appeals for the District of Columbia Circuit affirmed Order No. 561. The Court held that by establishing a general indexing methodology along with limited exceptions to indexed rates, FERC had reasonably balanced its dual responsibilities of ensuring just and reasonable rates and streamlining ratemaking through generally applicable procedures. The FERC indicated in Order No. 561 that it will assess in 2000 how the rate-indexing method is operating. In a proceeding involving Lakehead Pipe Line Company, Limited Partnership (Opinion No. 397), FERC concluded that there should not be a corporate income tax allowance built into a petroleum pipeline's rates to reflect income attributable to noncorporate partners since noncorporate partners, unlike corporate partners, do not pay a corporate income tax. This result comports with the principle that, although a regulated entity is entitled to an allowance to cover its incurred costs, including income taxes, there should not be an element included in the cost of service to cover costs not incurred. Opinion No. 397 was affirmed on rehearing in May 1996. Appeals of the Lakehead opinions were taken, but the parties to the Lakehead proceeding subsequently settled the case, with the result that appellate review of the tax and other issues never took place. A proceeding is also pending on rehearing at the FERC involving another publicly traded limited partnership engaged in the common carrier transportation of crude oil (the "Santa Fe Proceeding") in which the FERC could further limit its current position related to the tax allowance permitted in the rates of publicly traded partnerships, as well as possibly alter the FERC's current application of the FERC oil pipeline ratemaking methodology. On January 13, 1999, the FERC issued Opinion No. 435 in the Santa Fe Proceeding, which, among other things, affirmed Opinion No. 397's determination that there should not be a corporate income tax allowance built into a petroleum pipeline's rates to reflect income attributable to noncorporate partners. Requests for rehearing of Opinion No. 435 are pending before the FERC. Petitions for review of Opinion No. 435 are before the D.C. Circuit Court of Appeals, but are being held in abeyance pending FERC action on the rehearing requests. Once the FERC acts on rehearing, the FERC's position on the income tax allowance and on other rate issues could be subject to judicial review. Our Crude Oil Pipelines. The FERC generally has not investigated rates, such as those currently charged by us, which have been mutually agreed to by the pipeline and the shippers or which are significantly below cost of service rates that might otherwise be justified by the pipeline under the FERC's cost-based ratemaking methods. Substantially all of our gross margins on transportation are produced by rates that are either grandfathered or set by agreement of the parties. These rates have not been decreased through application of the indexing method. Rates for OCS crude are set by transportation agreements with shippers that do not expire until 2007 and provide for a minimum tariff with annual escalation. The FERC has twice approved the agreed OCS rates, although application of the PPFIG-1 index method would have required their reduction. When these OCS agreements expire in 2007, they will be subject to renegotiation or to any of the other methods for establishing rates under Order No. 561. As a result, we believe that the rates now in effect can be sustained, although no assurance can be given that the rates currently charged would ultimately be upheld if challenged. In addition, we do not believe that an adverse determination on the tax allowance issue in the Santa Fe Proceeding would have a detrimental impact upon our current rates. 23 Transportation and Sale of Natural Gas Prior to January 1993, the FERC, under the Natural Gas Policy Act of 1978 ("NGPA"), prescribed maximum lawful prices for natural gas sales. Effective January 1, 1993, natural gas prices were completely deregulated. Consequently, sales of our natural gas after such date have been made at market prices. The FERC regulates interstate natural gas pipeline transportation rates and service conditions, both of which affect our marketing of gas, as well as our revenues from sales of such gas. Since the latter part of 1985, culminating in 1992 in the Order No. 636 series of orders, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. FERC's "open access" policies are designed to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put gas sellers into more direct contractual relations with gas buyers. As a result of the Order No. 636 program, the marketing and pricing of natural gas has been significantly altered. The interstate pipelines' traditional role as wholesalers of natural gas has been terminated and replaced by regulations which require pipelines to provide transportation and storage service to others who buy and sell natural gas. In addition, on February 9, 2000, FERC issued Order No. 637, promulgating new regulations designed to refine the Order No. 636 "open access" policies and revise the rules applicable to capacity release transactions. These new rules will, among other things, permit existing holders of firm capacity to release or "sell" their capacity to others at rates in excess of FERC's regulated rate for transportation services. Although the FERC does not regulate natural gas producers such as ourselves, the agency's actions are intended to foster increased competition within all phases of the natural gas industry. To date, the FERC's pro-competition policies have not materially affected our business or operations. It is unclear what impact, if any, future rules or increased competition within the natural gas transportation industry will have on our gas sales efforts. Additional proposals and/or proceedings that might affect the natural gas industry may be considered by FERC, Congress, or state regulatory bodies. We cannot predict when or if any of these proposals may become effective or what effect, if any, they may have on our operations. The natural gas industry has historically been very heavily regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability and cash flow. In as much as laws and regulations are frequently expanded, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such regulations. We do not believe, however, that our operations will be affected any differently than other gas producers or marketers with which we compete. Regulation of Production The production of crude oil and natural gas is subject to regulation under a wide range of federal and state statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from crude oil and natural gas wells and the regulation of the spacing, plugging and abandonment of wells. Many states also restrict production to the market demand for oil and natural gas and several states have indicated interest in revising applicable regulations. The effect of these regulations is to limit the amount of oil and natural gas we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes an ad valorem, production or severance tax with respect to production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction. ENVIRONMENTAL REGULATION General Various federal, state and local laws and regulations governing the discharge of materials into the environment, or otherwise relating to the protection of the environment, affect our operations and costs. In particular, our activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and wastes are subject to stringent environmental regulation. As with the industry generally, compliance with existing and anticipated regulations increases our overall cost of business. Areas affected include capital costs to construct, maintain and upgrade equipment and facilities. While these regulations affect our capital expenditures and earnings, we believe that these regulations do not affect our competitive position in that the operations of our competitors that comply with such regulations are similarly affected. Environmental regulations have historically been subject to frequent change by regulatory authorities, and we are unable to predict the ongoing cost to us of complying with 24 these laws and regulations or the future impact of such regulations on our operations. Violation of federal or state environmental laws, regulations and permits can result in the imposition of significant civil and criminal penalties, injunctions and construction bans or delays. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent such event is not insured, subject us to substantial expense, including both the cost to comply with applicable regulations and claims by neighboring landowners and other third parties for personal injury and property damage. Although we obtained environmental studies on our properties in California, the Sunniland Trend and the Illinois Basin, and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than approximately 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In December 1995, we negotiated an agreement with Chevron, a prior owner of the LA Basin Properties, to remediate sections of the properties impacted by prior drilling and production operations. Under this agreement, Chevron agreed to investigate and potentially remediate specific areas contaminated with hazardous components, such as volatile organic substances and heavy metals, and we agreed to excavate and remediate nonhazardous crude oil contaminated soils. We are obligated to construct and operate (for the next 11 years) a minimum of five acres of bioremediation cells for crude oil contaminated soils designated for excavation and treatment by Chevron. While we believe that we do not have any material obligations for operations conducted prior to Stocker's acquisition of the properties from Chevron, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties (such as the Chevron agreement described above), there can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable from Chevron, either under the December 1995 agreement or the limited indemnity from Chevron contained in the original purchase agreement. A portion of our Sunniland Trend properties are located within the Big Cypress National Preserve and our operations therein are subject to regulations administered by the National Park Service ("NPS"). Under such regulations, a Master Plan of Operations has been approved by the Regional Director of the NPS. The Master Plan of Operations is a comprehensive plan of practices and procedures for our drilling and production operations designed to minimize the effect of such operations on the environment. The Master Plan of Operations must be modified and permits must be secured from the NPS for new wells which require the use of additional land for drilling operations. The Master Plan of Operations also requires that we restore the surface property affected by its drilling and production operations upon cessation of these activities. We do not anticipate that expenditures required to comply with such regulations will have a material adverse effect on its current operations. Approximately 183 acres of the 450 acres acquired in the Montebello Field have been designated as California Coastal Sage Scrub, a known habitat for the gnatcatcher, a species of bird designated as a federal threatened species under the Endangered Species Act. Approximately 40 pairs of gnatcatchers are believed to inhabit the property. In addition, the 450 acres acquired have been or will shortly be committed to the Natural Community Conservation Program/Coastal Sage Scrub Project, a voluntary conservation program. A variety of existing laws, rules and guidelines govern activities that can be conducted on properties that contain coastal sage scrub and gnatcatchers. These laws, rules and guidelines generally limit the scope of operations that can be conducted on such properties to those activities which do not materially interfere with such vegetation, the gnatcatcher or its habitat. While there can be no assurance that the presence of coastal sage scrub and gnatcatchers on the Montebello Field and existing or future laws, rules and guidelines will not prohibit or limit our operations and our planned activities or future commercial and/or residential development, we believe that we will be able to operate the existing wells and realize the reserve potential identified in our acquisition analysis without undue restrictions or prohibitions. Water The Oil Pollution Act ("OPA") was enacted in 1990 and amends provisions of the Federal Water Pollution Control Act of 1972 ("FWPCA") and other statutes as they pertain to prevention and response to oil spills. The OPA subjects owners of facilities to strict, joint and potentially unlimited liability for removal costs and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar laws. Regulations are currently being developed under OPA and state laws that may also impose additional regulatory burdens on our operations. The FWPCA imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA imposes substantial potential liability for the costs of removal, remediation and damages. We believe that compliance with existing permits and compliance with 25 foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations. Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in substantial compliance with these state requirements. Air Emissions Our operations are subject to the Federal Clean Air Act and comparable state and local statutes. We believe that our operations are in substantial compliance with these statutes in all states in which we operate. Amendments to the Federal Clean Air Act enacted in late 1990 (the "1990 Federal Clean Air Act Amendments") require or will require most industrial operations in the U.S. to incur capital expenditures in order to meet air emission control standards developed by the Environmental Protection Agency (the "EPA") and state environmental agencies. In addition, the 1990 Federal Clean Air Act Amendments include a new operating permit for major sources ("Title V permits"), which applies to some of our facilities. Although we can give no assurances, we believe implementation of the 1990 Federal Clean Air Act Amendments will not have a material adverse effect on our financial condition or results of operations. Solid Waste We generate non-hazardous solid wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA is considering the adoption of stricter disposal standards for non-hazardous wastes, including oil and gas wastes. RCRA also governs the disposal of hazardous wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as "hazardous wastes." Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. Such changes in the regulations could result in additional capital expenditures or operating expenses. Hazardous Substances The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund", imposes liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the site and companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of our ordinary operations, we may generate waste that falls within CERCLA's definition of a "hazardous substance." We may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which such hazardous substances have been disposed of or released into the environment. We currently own or lease, and have in the past owned or leased, properties where hydrocarbons are being or have been handled. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination. Hazardous Materials Transportation Requirements The DOT regulations affecting pipeline safety require pipeline operators to implement measures designed to reduce the environmental impact of oil discharge from onshore oil pipelines. These regulations require operators to maintain comprehensive spill response plans, including extensive spill response training for pipeline personnel. In addition, DOT regulations contain detailed specifications for pipeline operation and maintenance. We believe our operations are in substantial compliance with such regulations. 26 FEDERAL TAXATION For federal income tax purposes, Plains All American Inc. is the general partner of PAA, holding a direct and indirect ownership at December 31, 1999 of approximately 54% in PAA. Because PAA is a pass-through entity for tax purposes, the income or loss of PAA is generally allocated based upon the owners' respective ownership percentage. However, the Internal Revenue Code requires certain items of partnership income, deduction, gain or loss to be allocated so as to account for the difference between the tax basis and the fair market value of the property contributed to PAA by the general partner. The federal income tax burden associated with the difference between allocations based upon the fair market value of the property contributed by the general partner and the actual tax basis established for such property will be borne by the general partner. At December 31, 1999, we and our subsidiaries that are taxed as corporations for federal income tax purposes, which together file a consolidated federal income tax return, had remaining federal income tax net operating loss ("NOL") carryforwards of approximately $229.3 million and approximately $209.8 million of alternative minimum tax ("AMT") net operating loss carryforwards available as a deduction against future AMT income. In addition, we had approximately $0.3 million of enhanced oil recovery credits, $1.4 million of AMT credits and $7.0 million of statutory depletion carryforwards at December 31, 1999. The NOL carryforwards expire from 2005 through 2019. The value of these carryforwards depends on our ability to generate federal taxable income. In addition, for AMT purposes, only 90% of AMT income in any given year may be offset by AMT NOLs. Our ability to utilize NOL carryforwards to reduce our future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended (the "Code"). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury Regulations, and our offering of stock during any three-year period resulting in an aggregate change of more than 50% ("Ownership Change") in our beneficial ownership. In the event of an Ownership Change, Section 382 of the Code imposes an annual limitation on the amount of a corporation's taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (1) the fair market value of our equity multiplied by (2) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an Ownership Change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets sold. Although no assurances can be made, we do not believe that an Ownership Change has occurred as of December 31, 1999. Equity transactions after the date hereof by us or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an Ownership Change and therefore a limitation on the annual utilization of NOLs. In the event of an Ownership Change, the amount of our NOLs available for use each year will depend upon future events that cannot currently be predicted and upon interpretation of complex rules under Treasury Regulations. If less than the full amount of the annual limitation is utilized in any given year, the unused portion may be carried forward and may be used in addition to successive years' annual limitation. OTHER BUSINESS MATTERS We must continually acquire, explore for, develop or exploit new crude oil and natural gas reserves to replace those produced or sold. Without successful drilling, acquisition or exploitation operations, our crude oil and natural gas reserves and revenues will decline. Drilling activities are subject to numerous risks, including the risk that no commercially viable crude oil or natural gas production will be obtained. The decision to purchase, explore, exploit or develop an interest or property will depend in part on the evaluation of data obtained through geophysical and geological analyses and engineering studies, the results of which are often inconclusive or subject to varying interpretations. See Item 2. - "Properties -- Crude Oil and Natural Gas Reserves". The cost of drilling, completing and operating wells is often uncertain. Drilling may be curtailed, delayed or canceled as a result of many factors, including title problems, weather conditions, compliance with government permitting requirements, shortages of or delays in obtaining equipment, reductions in product prices or limitations in the market for products. The availability of a ready market for our crude oil and natural gas production also depends on a number of factors, including the demand for and supply of crude oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. Natural gas wells may be shut in for lack of a market or due to inadequacy or unavailability of natural gas pipeline or gathering system capacity. 27 Substantially all of our California crude oil and natural gas production and our Sunniland Trend oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could cause us to seek transportation alternatives, which in turn could result in increased transportation costs to us or involuntary curtailment of a significant portion of our crude oil and natural gas production. Our operations are subject to all of the risks normally incident to the exploration for and the production of crude oil and natural gas, including blowouts, cratering, oil spills and fires, each of which could result in damage to or destruction of crude oil and natural gas wells, production facilities or other property, or injury to persons. The relatively deep drilling conducted by us from time to time involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. Our operations in California, including transportation of crude oil by pipelines within the city of Los Angeles, are especially susceptible to damage from earthquakes and involve increased risks of personal injury, property damage and marketing interruptions because of the population density of the area. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against certain of these risks, including, in certain instances, earthquake risk in California, either because such insurance is not available or because of high premium costs. The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. A pipeline may experience damage as a result of an accident or other natural disaster. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damages and suspension of operations. We maintain insurance of various types that we consider to be adequate to cover our operations and properties. The insurance covers all of our assets in amounts considered reasonable. The insurance policies are subject to deductibles that we consider reasonable and not excessive. Our insurance does not cover every potential risk associated with operating pipelines, including the potential loss of significant revenues. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. With respect to all of our coverage, no assurance can be given that we will be able to maintain adequate insurance in the future at rates we consider reasonable. Our revenues are highly dependent upon the prices of, and demand for, crude oil and natural gas. Historically, the prices for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. The price we receive for our crude oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors beyond our control, including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other crude oil-producing and natural gas-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 94% of year-end 1999 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility. The benchmark NYMEX crude oil price of $25.60 per barrel at December 31, 1999 was more than double the $12.05 per barrel at the end of 1998. Although we are not currently experiencing any significant involuntary curtailment of our crude oil or natural gas production, market, logistic, economic and regulatory factors may in the future materially affect our ability to sell our production. In order to manage our exposure to price risks in the marketing of our crude oil and natural gas, from time to time we purchase put options, enter into fixed price delivery contracts, floating price collar arrangements, financial swaps and crude oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, we may sell a futures contract and thereafter either (1) make physical delivery of our product to comply with such contract or (2) buy a matching futures contract to unwind our futures position and sell our production to a customer. These same techniques are also utilized to manage price risk for certain production purchased from customers of PAA. Such contracts may expose us to the risk of financial loss in certain circumstances, including instances where production is less than expected, our customers fail to purchase or deliver the contracted quantities of crude oil or natural gas, or a sudden, unexpected event materially impacts crude oil or natural gas prices. Such contracts may also restrict our ability to benefit from unexpected increases in crude oil and natural gas prices. See Item 7. -- "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook" and Item 7a. -- "Quantitative and Qualitative Disclosures about Market Risks". 28 TITLE TO PROPERTIES Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interferes with the use of such properties in the operation of our business. We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. Title investigation is made and title opinions of local counsel are generally obtained only before commencement of drilling operations. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property and in some instances such rights- of-way are revocable at the election of the grantor. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. We have obtained permits from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. We have also obtained permits from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. In some cases, property for pipeline purposes was purchased in fee. All of the pump stations are located on property owned in fee or property under long-term leases. In certain states and under certain circumstances, we have the right of eminent domain to acquire rights-of-way and lands necessary for our common carrier pipelines. Some of the leases, easements, rights-of-way, permits and licenses transferred to PAA, upon its formation in 1998 and in connection with acquisitions they have made since that time, required the consent of the grantor to transfer such rights, which in certain instances is a governmental entity. We believe that we have obtained such third-party consents, permits and authorizations that are sufficient for the transfer to us of the assets necessary for us to operate our business in all material respects as described in this report. With respect to any consents, permits or authorizations which have not yet been obtained, we believe that such consents, permits or authorizations will be obtained within a reasonable period, or that the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business. We believe that we have satisfactory title to all of our other assets. Although title to such properties are subject to encumbrances in certain cases, such as customary interests generally retained in connection with acquisition of real property, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens and minor easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition by PAA's predecessor or us, we believe that none of such burdens will materially detract from the value of such properties or from our interest therein or will materially interfere with their use in the operation of our business. EMPLOYEES As of December 31, 1999, we had approximately 1,080 full-time employees, none of whom is represented by any labor union. Approximately 675 of such full-time employees are field personnel involved in crude oil and natural gas producing activities, trucking and transport activities and crude oil terminalling and storage activities. Approximately 910 employees spend the majority of their time on the business of PAA. ITEM 2. PROPERTIES We are an independent energy company that acquires, exploits, develops, explores and produces crude oil and natural gas. Through our majority ownership in PAA, we are also engaged in the midstream activities of marketing, transportation, terminalling and storage of crude oil. Our crude 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. OIL AND NATURAL GAS RESERVES The following tables set forth certain information with respect to our reserves based upon reserve reports prepared by the independent petroleum consulting firms of H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., and Ryder Scott Company in 1999, 1998 and 1997, and in addition in 1997 by System Technology Associates, Inc. Such reserve 29 volumes and values were determined under the method prescribed by the SEC which requires the application of year-end prices for each year, held constant throughout the projected reserve life.
AS OF OR FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------- 1999 1998 1997 ----------------------------------------------------------------------------------- OIL GAS OIL GAS OIL GAS (BBL) (MCF) (BBL) (MCF) (BBL) (MCF) ----------------------------------------------------------------------------------- (IN THOUSANDS) PROVED RESERVES Beginning balance 120,208 86,781 151,627 60,350 115,996 37,273 Revision of previous estimates 62,895 (8,234) (46,282) 2,925 (16,091) 3,805 Extensions, discoveries, improved recovery and other additions 37,393 15,488 14,729 29,306 17,884 8,126 Sale of reserves in-place - - - (2,799) (26) (547) Purchase of reserves in-place 6,442 - 7,709 - 40,764 14,566 Production (8,016) (3,162) (7,575) (3,001) (6,900) (2,873) ------- ------- ------- ------ ------- ------ Ending balance 218,922 90,873 120,208 86,781 151,627 60,350 ======= ====== ======= ====== ======= ====== PROVED DEVELOPED RESERVES Beginning balance 73,264 58,445 99,193 38,233 86,515 25,629 ======= ====== ======= ====== ======= ====== Ending balance 120,141 49,255 73,264 58,445 99,193 38,233 ======= ====== ======= ====== ======= ======
The following table sets forth the pre-tax Present Value of Proved Reserves at December 31, 1999, 1998 and 1997.
1999 1998 1997 ------------- ------------- ------------- (in thousands) Proved developed $ 721,151 $185,961 $386,463 Proved undeveloped 524,898 40,982 124,530 ---------- -------- -------- Total Proved $1,246,049 $226,943 $510,993 ========== ======== ========
There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Present Value of Proved Reserves shown above represents estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The information set forth in the preceding tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. A large portion of our reserve base (approximately 94% of year-end 1999 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility. Revisions of previous estimates set forth above, including upward price related revisions, were 64 million BOE in 1999 and, including downward price related revisions, were 46 million BOE and 16 million BOE in 1998 and 1997, respectively. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook". In accordance with the SEC guidelines, the reserve engineers' estimates of future net revenues from our properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The crude oil price in effect at December 31, 1999 is based on the year-end crude oil price with variations therefrom based on location and quality of crude oil. We 30 have entered into various arrangements to fix the NYMEX crude oil price for a significant portion of our crude oil production. On December 31, 1999, these arrangements provided for a NYMEX crude oil price for 18,500 barrels per day from January 1, 2000, through December 31, 2000, at approximately $16.00 per barrel. Approximately 10,000 barrels per day of the volumes hedged in 2000 will participate in price increases above the $16.00 per barrel floor price, subject to a ceiling limitation of $19.75 per barrel. Location and quality differentials attributable to our properties are not included in the foregoing prices. Arrangements in effect at December 31, 1999 are reflected in the reserve reports through the term of the arrangements. The overall average prices used in the reserve reports as of December 31, 1999 were $20.94 per barrel of crude oil, condensate and natural gas liquids and $2.77 per Mcf of natural gas. See Item 1. -- "Business -- Product Markets and Major Customers". Prices for natural gas and, to a lesser extent, oil are subject to substantial seasonal fluctuations and prices for each are subject to substantial fluctuations as a result of numerous other factors. Since December 31, 1998, we have not filed any estimates of total proved net crude oil or natural gas reserves with any federal authority or agency other than the SEC. See Note 20 in our consolidated financial statements appearing elsewhere in this report for certain additional information concerning our proved reserves. PRODUCTIVE WELLS AND ACREAGE As of December 31, 1999, we had working interests in 1,811 gross (1,796 net) active oil wells. The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 1999.
DECEMBER 31, 1999 -------------------------------------------------------------------------------------- DEVELOPED ACRES (1) UNDEVELOPED ACRES (2) --------------------------------------- --------------------------------------- GROSS NET GROSS NET (3) ---------------- ---------------- ---------------- ---------------- Onshore California (4) 9,049 9,003 3,180 1,702 Offshore California 15,326 4,033 41,720 1,449 Florida (5) 12,182 12,182 82,048 78,096 Illinois 16,412 14,423 16,250 7,940 Indiana 1,155 854 1,280 575 Kansas - - 48,147 37,647 Kentucky - - 1,321 521 Louisiana - - 4,875 4,858 ------ ------ ------- ------- Total 54,124 40,495 198,821 132,788 ====== ====== ======= =======
- ------------ (1) Developed acres are acres spaced or assigned to productive wells. (2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. (3) Less than 10% of total net undeveloped acres are covered by leases that expire from 2000 through 2003. (4) Does not include 9,000 acres covered by a farmout from Chevron, in which we own a 50% interest. (5) Does not include 29,000 gross (28,000 net) acres under a seismic option. 31 DRILLING ACTIVITIES Certain information with regard to our drilling activities during the years ended December 31, 1999, 1998 and 1997 is set forth below:
YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------------------------------------------- 1999 1998 1997 --------------------------- --------------------------------- --------------------------------- GROSS NET GROSS NET GROSS NET ----------- ----------- -------------- -------------- -------------- -------------- Exploratory Wells: Oil - - - - 2.00 2.00 Natural gas - - - - - - Dry 1.00 0.50 - - - - ------ ------ ----- ----- ----- ----- Total 1.00 0.50 - - 2.00 2.00 ====== ====== ===== ===== ===== ===== Development Wells: Oil 105.00 105.00 76.00 76.00 58.00 57.06 Natural gas - - - - - - Dry - - - - - - ------ ------ ----- ----- ----- ----- Total 105.00 105.00 76.00 76.00 58.00 57.06 ====== ====== ===== ===== ===== ===== Total Wells: Oil 105.00 105.00 76.00 76.00 60.00 59.06 Natural gas - - - - - - Dry 1.00 0.50 - - - - ------ ------ ----- ----- ----- ----- Total 106.00 105.50 76.00 76.00 60.00 59.06 ====== ====== ===== ===== ===== =====
See Item 1. - "Business -- Acquisition and Exploitation" and -- "Productive Wells and Acreage" for additional information regarding exploitation activities, including waterflood patterns, workovers and recompletions. PRODUCTION AND SALES The following table presents certain information with respect to crude oil and natural gas production attributable to our properties, the revenue derived from the sale of such production, average sales prices received and average production costs during the three years ended December 31, 1999, 1998 and 1997.
YEAR ENDED DECEMBER 31, --------------------------------------- 1999 1998 1997 ------------ ------------ ----------- (IN THOUSANDS EXCEPT PER UNIT DATA) Production: Crude oil and natural gas liquids (Bbls) 8,016 7,574 6,900 Natural gas (Mcf) 3,163 3,001 2,873 BOE 8,543 8,075 7,379 Revenue: Crude oil and natural gas liquids $111,128 $ 98,664 $104,988 Natural gas 5,095 4,090 4,415 -------- -------- -------- Total $116,223 $102,754 $109,403 ======== ======== ======== Average sales price: Crude oil and natural gas liquids per Bbl $ 13.85 $ 13.03 $ 15.22 Natural gas per Mcf 1.61 1.36 1.54 Per BOE 13.61 12.73 14.83 Production expenses per BOE 6.51 6.29 6.16
PAA PROPERTIES See description of PAA's properties under Item 1. -- "Business -- Midstream Activities". 32 ITEM 3. 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, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases were filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. Plaintiffs allege that the defendants are 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. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of our common stock and options and (2) purchasers of PAA's common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed. 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 Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed. We intend to vigorously defend the claims made in the Texas securities 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 or results of operation. 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. We have reached an agreement in principle to settle with the Hughes group. In consideration for full and final settlement, and dismissal with prejudice, we have agreed to pay to the Hughes group the total sum of $100,000. We and Exxon have filed motions for summary judgment with respect to the claims of the remaining parties. The court has not yet set a date for hearing of these motions. The trial date is currently scheduled in June 2000. We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings in which our exposure, individually and in the aggregate, is not considered material. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of the security holders, through solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this report. 33 EXECUTIVE OFFICERS OF THE COMPANY Information regarding our executive officers is presented below. All executive officers hold office until their successors are elected and qualified. Greg L. Armstrong, President and Chief Executive Officer Officer Since 1981 Mr. Armstrong, age 41, has been President, Chief Executive Officer and a director since 1992. He was President and Chief Operating Officer from October to December 1992, and Executive Vice President and Chief Financial Officer from June to October 1992. He was Senior Vice President and Chief Financial Officer from 1991 to June 1992, Vice President and Chief Financial Officer from 1984 to 1991, Corporate Secretary from 1981 to 1988, and Treasurer from 1984 to 1987. William C. Egg, Jr., Executive Vice President Officer Since 1984 Mr. Egg, age 48, has been Executive Vice President and Chief Operating Officer-Upstream since May 1998. He was Senior Vice President from 1991 to 1998. He was Vice President-Corporate Development from 1984 to 1991 and Special Assistant-Corporate Planning from 1982 to 1984. Cynthia A. Feeback, Vice President - Accounting Officer Since 1993 and Assistant Treasurer Ms. Feeback, age 42, has been Vice President and Assistant Treasurer since May 1999. She was Assistant Treasurer, Controller and Principal Accounting Officer of the Company from May 1998 to May 1999. She was Controller and Principal Accounting Officer from 1993 to 1998. She was Controller from 1990 to 1993 and Accounting Manager from 1988 to 1990. Jim G. Hester, Vice President - Business Development Officer Since 1999 and Acquisitions Mr. Hester, age 40, has been Vice President -- Business Development and Acquisitions since May 1999. He was Manager of Business Development and Acquisitions from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990. Phillip D. Kramer, Executive Vice President, Chief Officer Since 1987 Financial Officer and Treasurer Mr. Kramer, age 44, has been Executive Vice President, Chief Financial Officer and Treasurer since May 1998. He was Senior Vice President and Chief Financial Officer from May 1997 to May 1998. He was Vice President and Chief Financial Officer from 1992 to 1997, Vice President and Treasurer from 1988 to 1992, Treasurer from 1987 to 1988, and Controller from 1983 to 1987. Michael R. Patterson, Vice President and General Counsel Officer Since 1985 Mr. Patterson, age 52, has been Vice President and General Counsel since 1985 and Corporate Secretary since 1988. Harry N. Pefanis, Executive Vice President Officer Since 1988 Mr. Pefanis, age 42, has been Executive Vice President-Midstream since May 1998. He was Senior Vice President from February 1996 to May 1998. He had been Vice President-Products Marketing since 1988. From 1987 to 1988 he was Manager of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate Planning. Mr. Pefanis is also President and Chief Operating Officer of Plains All American Inc. Mary O. Peters, Vice President - Administration and Officer Since 1991 Human Resources Ms. Peters, age 51, has been Vice President-Administration and Human Resources since 1991. She was Manager of Office Administration from 1984 to 1991. 34 PART II Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS Our common stock is listed and traded on the American Stock Exchange under the symbol "PLX". The number of stockholders of record of the common stock as of March 15, 2000 was 1,133. The following table sets forth the range of high and low closing sales prices for the common stock as reported on the American Stock Exchange Composite Tape for the periods indicated below.
HIGH LOW ---------- --------- 1999: 1st Quarter $15 1/2 $ 8 1/8 2nd Quarter 20 3/16 13 1/8 3rd Quarter 20 16 1/4 4th Quarter 20 9 1/16 1998: 1st Quarter $17 13/16 $14 7/16 2nd Quarter 21 16 7/8 3rd Quarter 19 3/4 14 5/8 4th Quarter 18 7/8 13 5/8
We have not paid cash dividends on shares of our common stock since our inception and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, we are restricted by provisions of the indentures governing the issue of $275.0 million 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and prohibited by our $225.0 million revolving credit facility from paying dividends on our common stock. On December 14, 1999, we sold in a private placement 50,000 shares of our Series F Preferred Stock for $50.0 million. Each share of the Series F Preferred Stock has a stated value of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable semi-annually in either cash or additional shares of Series F Preferred Stock at our option and are cumulative from the date of issue. Dividends paid in additional shares of Series F Preferred Stock are limited to an aggregate of six dividend periods. Each share of Series F Preferred Stock is convertible into 81.63 shares of common stock (an initial effective conversion price of $12.25 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any sixty-day trading period is equal to or greater than $21.60 per share. After December 15, 2003, the Series F Preferred Stock is redeemable at our option at 110% of stated value through December 15, 2004, and at declining amounts thereafter. If not previously redeemed or converted, the Series F Preferred Stock is required to be redeemed in 2007. On April 1, 1999, we paid a dividend on our Series E Preferred Stock for the period from October 1, 1998 through March 31, 1999. The dividend amount of approximately $4.1 million was paid by issuing 8,209 additional shares of the Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E Preferred Stock, including accrued dividends, were converted into 98,613 shares of common stock at a conversion price of $18.00 per share. On October 1, 1999, we paid a cash dividend of approximately $4.2 million on the Series E Preferred Stock for the period April 1, 1999 through September 30, 1999. On March 22, 2000, our Board of Directors declared cash dividends on our Series D Preferred Stock, Series F Preferred Stock and Series G Preferred Stock, all of which are payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $350,000 on the Series D Preferred Stock is for the period January 1, 2000 through March 31, 2000. The dividend amount of $1,475,000 on the Series F Preferred Stock is for the period December 15, 1999 (the date of original issuance) through March 31, 2000. The dividend amount of $4,219,000 for the Series G Preferred Stock is for the period October 1, 1999 through March 31, 2000. 35 ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT FOR PER SHARE DATA) The following selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and "Item 7. -- Management's Discussion and Analysis of Financial Condition and Results of Operations" (in thousands, except per share information).
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 1999(1) 1998(1) 1997 1996 1995 ---------- ---------- --------- -------- --------- (RESTATED) (RESTATED) Statement of Operations Data: Revenues: Oil and natural gas sales $ 116,223 $ 102,754 $109,403 $ 97,601 $ 64,080 Marketing, transportation, storage and terminalling revenues 4,626,467 1,129,689 752,522 531,698 339,826 Gain on PAA unit offerings (2) 9,787 60,815 - - - Gain on sale of linefill 16,457 - - - - Interest and other income 1,237 834 319 309 319 ---------- ---------- --------- -------- -------- Total revenue 4,770,171 1,294,092 862,244 629,608 404,225 ---------- ---------- --------- -------- -------- Expenses: Production expenses 55,645 50,827 45,486 38,735 30,256 Marketing, transportation, storage and terminalling expenses 4,518,777 1,091,328 740,042 522,167 333,460 Unauthorized trading losses and related expenses (1) 166,440 7,100 - - - General and administrative 31,402 10,778 8,340 7,729 7,215 Depreciation, depletion and amortization 36,998 31,020 23,778 21,937 17,036 Reduction of carrying cost of oil and natural gas properties (3) - 173,874 - - - Interest expense 46,378 35,730 22,012 17,286 13,606 Litigation settlement - - - 4,000(4) - ---------- ---------- --------- -------- -------- Total expenses 4,855,640 1,400,657 839,658 611,854 401,573 ---------- ---------- --------- -------- -------- Income (loss) before income taxes, minority interest and extraordinary item (85,469) (106,565) 22,586 17,754 2,652 Minority interest (40,203) 786 - - - Income tax expense (benefit): Current (7) 862 352 - - Deferred (20,472) (45,867) 7,975 (3,898) - ---------- ---------- --------- -------- -------- Income (loss) before extraordinary item (24,787) (62,346) 14,259 21,652 2,652 Extraordinary item, net of tax benefit and minority interest (5) (544) - - (5,104) - ---------- ---------- --------- -------- -------- Net income (loss) (25,331) (62,346) 14,259 16,548 2,652 Less: cumulative preferred stock dividends 10,026 4,762 163 - - ---------- ---------- --------- -------- -------- Net income (loss) applicable to common shareholders $ (35,357) $ (67,108) $ 14,096 $ 16,548 $ 2,652 ========== ========== ========= ======== ======== Income (loss) per common share - basic: Before extraordinary item $ (2.02) $ (3.99) $ 0.85 $ 1.32 $ 0.19 Extraordinary item, net of income taxes (0.03) - - (0.31) - ---------- ---------- --------- -------- --------- $ (2.05) $ (3.99) $ 0.85 $ 1.01 $ 0.19 ========== ========== ========= ======== ========= Income (loss) per common share - assuming dilution: Before extraordinary item $ (2.02) $ (3.99) $ 0.77 $ 1.23 $ 0.16 Extraordinary item, net of income taxes (0.03) - - (0.29) - ---------- ---------- --------- -------- --------- $ (2.05) $ (3.99) $ 0.77 $ 0.94 $ 0.16 ========== ========== ========= ======== ========= Table and footnotes continued on following page
36
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------- 1999 1998 (1) 1997 1996 1995 ---------- ---------- -------- -------- -------- (RESTATED) Other Financial Data: Cash flow from operations (6) $ 70,382 $ 42,033 $ 46,233 $ 39,942 $ 19,688 EBITDA (7) 139,116 80,344 68,376 56,977 33,294 Net cash provided by (used in) operating activities (75,964) 37,630 30,307 39,008 16,984 Net cash used in investing activities 266,396 483,422 107,634 52,496 64,398 Net cash provided by financing activities 404,044 448,622 78,524 9,876 52,252 AS OF DECEMBER 31, ----------------------------------------------------------------------- 1999 1998 (1) 1997 1996 1995 ---------- ---------- -------- -------- -------- (RESTATED) Balance Sheet Data: Cash and cash equivalents $ 68,228 $ 6,544 $ 3,714 $ 2,517 $ 6,129 Working capital (deficit) (8) 115,867 (21,041) (6,011) (4,843) (4,749) Property and equipment, net 787,653 661,726 413,308 311,040 280,538 Total assets 1,689,560 972,838 556,819 430,249 352,046 Long-term debt 676,703 431,983 285,728 225,399 205,089 Other long-term liabilities 21,107 10,253 5,107 2,577 1,547 Redeemable preferred stock 138,813 88,487 - - - Non-redeemable preferred stock, common stock and other stockholders' equity 40,619 69,170 133,193 95,572 77,029
- ----------- (1) 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). Approximately $7.1 million was recognized in 1998 and the remainder in 1999. As a result we have restated our 1998 financial information. See Item 1. -- "Business -- Unauthorized Trading Losses". We have restated 1999 marketing, transportation, storage and terminalling revenues and expenses to appropriately reflect certain transactions between the upstream and midstream lines of business. (2) For 1999, includes a $9.8 million noncash gain related to the change in our ownership of PAA resulting from PAA's 1999 public offering of common units. For 1998, includes a $60.8 million noncash gain recognized upon the formation of PAA. See Item 7. -- "Management's Discussion and Analysis of Financial Condition and Results of Operations". (3) Includes a $173.9 million pre-tax ($109.0 million after tax) noncash charge related to a writedown of the capitalized costs of our proved crude oil and natural gas properties due to low crude oil prices at December 31, 1998. See Item 7.-- "Management's Discussion and Analysis of Financial Condition and Results of Operations". (4) Represents charge related to the settlement of two lawsuits filed in 1992 and 1993. (5) Relates to the early redemption of PAA debt in 1999 and of our 12% Senior Subordinated Notes in 1996. (6) Represents net cash provided by operating activities after minority interest but before changes in assets and liabilities and other noncash items. (7) EBITDA means earnings before interest, taxes and DD&A. Adjusted EBITDA also excludes unauthorized trading losses, noncash compensation expense, restructuring expense, gain on unit offerings, linefill gain and extraordinary loss from extinguishment of debt. Adjusted EBITDA is not a measurement presented in accordance with generally accepted accounting principles ("GAAP") and is not intended to be used in lieu of GAAP presentations of results of operations and cash provided by operating activities. EBITDA is commonly used by debt holders and financial statement users as a measurement to determine the ability of an entity to meet its interest obligations. (8) For working capital includes $37.9 million of pipeline linefill and $103.6 million for the segment of the All American Pipeline that were both sold in the first quarter of 2000. See Item 1. -- "Midstream Acquisitions and Dispositions -- All American Pipeline Linefill Sale and Asset Disposition". 37 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General We are an independent energy company that is 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. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in PAA. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. 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). Approximately $7.1 million of the unauthorized trading loss was recognized in 1998 and the remainder in 1999. As a result, we have restated our 1998 financial information. See Item 1. "Business - Unauthorized Trading Losses" for a discussion of the unauthorized trading loss, its financial effects and the steps taken to prevent future violations of PAA's trading policies. Results of Operations For the year ended December 31, 1999, we reported a net loss of $25.3 million, or $2.05 per share on total revenue of $4.8 billion as compared to a net loss of $62.3 million, or $3.99 per share on total revenue of $1.3 billion in 1998. For the year ended December 31, 1997, we reported net income of $14.3 million or $0.85 per share ($0.77 per share diluted), on total revenue of $862.2 million. The net losses for the years ended December 31, 1999 and 1998 include the following unusual or nonrecurring items: 1999 . $166.4 million of unauthorized trading losses; . a $16.5 million gain on the sale of crude oil linefill that was sold in 1999; . a $6.0 million after-tax gain ($9.8 million pre-tax) related to the sale of units by PAA; . restructuring expense of $1.4 million; and . an extraordinary loss of $0.5 million related to the early extinguishment of debt (net of minority interest and tax benefit). 1998 . $7.1 million of unauthorized trading losses; . a $109.0 million after-tax ($173.9 million pre-tax) reduction in carrying cost of oil and natural gas properties due to low crude oil prices at December 31, 1998; and . a $37.1 million after-tax ($60.8 million pre-tax) gain associated with the initial public offering of PAA. Excluding these nonrecurring items we would have reported net income of approximately $17.0 million and $8.4 million in 1999 and 1998, respectively. Adjusted EBITDA increased 73% in 1999 to $139.1 million from the $80.3 million reported in 1998 and 103% from the $68.4 million reported in 1997. Cash flow from operations (net income before noncash items) was $70.4 million, $42.0 million and $46.2 million in 1999, 1998 and 1997, respectively. Adjusted EBITDA and cash flow from operations exclude the nonrecurring items discussed above. Oil and natural gas sales. Oil and natural gas sales were $116.2 million in 1999, an increase of $13.5 million over 1998 due to higher product prices and increased production volumes which contributed approximately $7.5 million and $6.0 million to the increase, respectively. Oil and natural gas revenues decreased to $102.8 million in 1998 as compared to $109.4 million in 1997 due to decreased product prices, which had an approximate $16.9 million negative impact, offset by increased production volumes, which had the effect of increasing revenues by approximately $10.3 million. 38 Marketing, transportation, storage and terminalling revenues. Marketing, transportation, storage and terminalling revenues increased to $4.6 billion from $1.1 billion and $0.8 billion in 1998 and 1997, respectively. The increase in 1999 as compared to 1998 was primarily due to an increase in lease gathering and bulk purchase volumes, resulting from the Scurlock acquisition in May 1999, and higher crude oil prices. The increase in 1998 from 1997 reflects the acquisition of the All American Pipeline in July 1998 as well as increased lease gathering and bulk purchase volumes. These increases in 1998 were partially offset by lower crude oil prices. The NYMEX benchmark WTI crude oil price averaged $19.25 per barrel in 1999, $14.43 per barrel in 1998, and $20.63 per barrel in 1997. See "Midstream Results". Production expenses. Total production expenses increased to $55.6 million from $50.8 million and $45.5 million in 1998 and 1997, respectively, primarily due to increased production volumes resulting from our acquisition and exploitation activities. Marketing, transportation, storage and terminalling expenses. Marketing, transportation, storage and terminalling expenses increased to $4.5 billion from $1.1 billion and $0.7 billion in 1998 and 1997, respectively. The increase in 1999 as compared to 1998 was primarily due to an increase in lease gathering and bulk purchase volumes, resulting from the Scurlock acquisition in May 1999, and higher crude oil prices. The increase in 1998 from 1997 reflects the acquisition of the All American Pipeline in July 1998 as well as increased lease gathering and bulk purchase volumes. These increases in 1998 were partially offset by lower crude oil prices. General and administrative. General and administrative expenses were $31.4 million for the year ended December 31, 1999, compared to $10.8 million and $8.3 million for 1998 and 1997, respectively. Our upstream and midstream activities accounted for approximately $3.3 million and $17.3 million, respectively, of the increase from 1998 to 1999 and $0.7 million and $1.8 million, respectively, of the increase from 1997 to 1998. Noncash compensation expense. During 1999, we incurred a charge of $1.0 million related to noncash incentive compensation paid to certain officers and key employees of Plains All American Inc., the general partner of PAA. In 1998, Plains All American Inc. granted the employees the right to earn ownership in common units of PAA owned by Plains All American Inc. The units vest over a three-year period subject to PAA paying distributions on the common and subordinated units. This amount is included in general and administrative expense on the Consolidated Statements of Operations. Depreciation, depletion and amortization. Primarily as a result of the aforementioned midstream acquisitions and increased upstream production levels, total DD&A expense for the year ended December 31, 1999, was $37.0 million as compared to $31.0 million and $23.8 million in 1998 and 1997, respectively. Interest expense. Interest expense, net of capitalized interest, for 1999 increased to $46.4 million as compared to $35.7 million in 1998 and $22.0 million in 1997. The increase in 1999 is primarily due to (1) interest associated with the debt incurred for the Scurlock and West Texas Gathering System acquisitions, (2) interest for a full year on debt outstanding from the All American Pipeline acquisition, (3) an increase in interest related to hedged inventory transactions (4) higher debt levels related to our acquisition, exploitation, development and exploration activities and (5) higher interest rates. The increase in interest expense in 1998 is primarily associated with the debt incurred for the acquisition of the All American Pipeline and the SJV Gathering System and our upstream acquisition, exploitation, development and exploration activities. During 1999, 1998 and 1997, we capitalized $4.4 million, $3.7 million and $3.3 million of interest, respectively. Provision (benefit) for income taxes. For the year ended December 31, 1999, we recognized a deferred tax benefit of $20.5 million. For the year ended December 31, 1998, we recognized a deferred tax benefit of $45.9 million and a current tax provision of $0.9 million. For the year ended December 31, 1997, we recognized a deferred tax provision of $8.0 million and a current tax provision of $0.4 million. At December 31, 1999, we have a net deferred tax asset of $69.0 million, primarily attributable to net operating loss carryforwards. The minimum amount of future taxable income necessary to utilize the net operating loss carryforwards is $229.3 million. Based on current levels of pre-tax income, excluding nonrecurring items, management believes that it is more likely than not that we will generate taxable income from operations sufficient to realize the deferred tax asset. Nonrecurring Items Gain on PAA unit offerings. In 1999, we recognized a pre-tax gain of $9.8 million ($6.0 million after-tax) in connection with PAA's October 1999 public offering. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of the units. We held approximate interests of 59% and 54% before and after this offering, respectively. During 1998, we recognized a pre- tax gain of $60.8 million ( 39 approximately $37.1 million after-tax) in connection with the formation of PAA as a result of an increase in the book value of our equity as previously discussed. The formation-related expenses consist primarily of amounts due to certain key employees in connection with the successful formation of PAA and debt prepayment penalties. PAA may in the future issue additional units in public or private sales if it needs additional capital and if market conditions are favorable. Such sales could reduce our ownership in PAA and could generate additional gains. 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 substantially completed in February 2000. The linefill was located in the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas. Proceeds from the sale of the linefill were approximately $100.0 million, net of associated costs, and were used for working capital purposes. We estimate that we will recognize a total gain of approximately $44.6 million in connection with the sale of the linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. Unauthorized trading losses. As previously discussed, we recognized losses of approximately $166.4 million and $7.1 million in 1999 and 1998, respectively, as a result of unauthorized trading by a former employee. Restructuring charge. A $1.4 million restructuring charge, primarily associated with severance-related expenses of 24 employees who were terminated, was incurred by PAA in 1999. Approximately $1.1 million of these costs are included in marketing, transportation, storage and terminalling expenses and approximately $0.3 million are included general and administrative expenses. As of December 31, 1999, all severance costs were paid and the terminated employees were not employed by PAA. As a result of the restructuring, PAA expects to reduce cash compensation costs by approximately $1.3 million per year. Extraordinary item. The extraordinary item of $0.5 million (net of minority interest of $.07 million and deferred tax of $0.3 million) in 1999 relates to the write-off of certain debt issue costs and penalties associated with the prepayment of debt. Reduction in carrying cost of oil and natural gas properties. In 1998, we incurred an impairment of our oil and natural gas properties due to low crude oil prices at December 31, 1998. Under full-cost accounting rules, unamortized costs of proved oil and natural gas properties are subject to a ceiling, which limits such costs. At December 31, 1998, the capitalized costs of our proved oil and natural gas properties exceeded this limit and we reduced the carrying cost of those properties by $109.0 million after tax ($173.9 million pre-tax). Upstream Results The following table sets forth certain of our upstream operating information for the periods presented.
Year Ended December 31, ----------------------------------------------------- 1999 1998 1997 ------------- ------------- ------------- (in thousands, except per unit data) Average Daily Production Volumes: Barrels of oil equivalent California (approximately 91% oil) 15.6 13.8 11.2 Offshore California (100% oil) 2.2 - - Gulf Coast (100% oil) 2.6 4.8 5.3 Illinois Basin (100% oil) 3.0 3.5 3.6 Sold properties - - 0.1 ------------ ------------ ------------ Total (approximately 94% oil) 23.4 22.1 20.2 ============ ============ ============ Unit Economics: Average sales price per BOE $ 13.61 $ 12.73 $ 14.83 Production expense per BOE 6.51 6.29 6.16 ------------ ------------ ------------ Gross margin per BOE 7.10 6.44 8.67 Upstream G&A expense per BOE 0.85 0.68 0.65 ------------ ------------ ------------ Gross profit per BOE $ 6.25 $ 5.76 $ 8.02 ============ ============ ============
Total oil equivalent production increased approximately 6% to an average of 23,400 BOE per day over the 1998 level of 22,100 BOE per day and 16% above the 1997 level of 20,200 BOE per day. The volume increase in 1999 is primarily associated with our ongoing acquisition and exploitation activities, offset somewhat by decreased production from certain of our other properties. The offshore California Point Arguello Unit, which we acquired from Chevron in July 1999, accounted 40 for approximately 2,200 BOE per day of the increase. Net daily production from our onshore California properties increased to approximately 15,600 BOE per day in 1999, up 1,800 BOE per day, or 13% over 1998 and 39% over 1997, due to our acquisition and exploitation activities. Excluding production from the Mt. Poso Field, which we acquired in December 1998, California production was up 6% from 1998. The increase in 1998 as compared to 1997 is partially attributable to the acquisition of the Arroyo Grande Field in the fourth quarter of 1997. Net daily production for our Gulf Coast properties averaged approximately 2,600 BOE per day in 1999, compared to 4,800 BOE per day in 1998 and 5,300 BOE per day in 1997. The Gulf Coast production decrease is due to downtime as a result of mechanical problems and the effects of natural decline. During 1998 and 1999, several wells in this area had mechanical problems and were not returned to production due to lower operating margins. We expect that the rate of production decline in this area will decrease from the levels discussed above, as several wells have been returned to production due to higher crude oil prices and overall decline rates are flattening out. Net daily production for this area was approximately 2,700 barrels per day in May 2000. Net daily production in the Illinois Basin averaged 3,000 BOE per day during 1999, 3,500 BOE per day in 1998 and 3,600 BOE per day in 1997. The decrease is primarily due to natural decline and the impact of wells that were shut-in due to low crude oil prices in 1998. Our product price averaged $13.61 per BOE in 1999, 7% higher than the price received in 1998 and 8% lower than the price received in 1997. Our product price represents a combination of fixed and floating price arrangements, typically tied to a benchmark price index and subjected to discounts for location and quality differentials. The price index is the NYMEX benchmark WTI crude oil price, which averaged $19.25 per barrel in 1999, $14.43 per barrel in 1998, and $20.63 per barrel in 1997. 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 the overall average price we received (relative to the price we would have received in the absence of hedging) by $1.30 per BOE in 1999, increasing the price by $2.98 per BOE in 1998 and decreasing the price by $1.26 per BOE in 1997. We maintained hedges on approximately 63% of our crude oil production throughout 1999 at an average NYMEX WTI crude oil price of approximately $18.00 per barrel. We routinely hedge a portion of our crude oil production. See "Outlook" and Item 7a. - "Quantitative and Qualitative Disclosures about Market Risk". Upstream unit gross margin (well-head revenue less production expenses) for 1999 was $7.10 per BOE, compared to $6.44 per BOE in 1998 and $8.67 per BOE in 1997. Average unit production expenses were $6.51 per BOE, $6.29 per BOE and $6.16 per BOE in 1999, 1998, and 1997, respectively. Unit general and administrative expense increased to $0.85 per BOE in 1999 compared to $0.68 per BOE during 1998 and $0.65 per BOE during 1997. Total upstream general and administrative expense was $7.8 million, $5.5 million and $4.8 million in 1999, 1998 and 1997, respectively. The increase in 1999 as compared to 1998 is primarily attributable to increased personnel costs (approximately $0.8 million), expenses related to our Year 2000 computer readiness project (approximately $0.4 million), and legal expenses (approximately $0.4 million). The increase in 1998 as compared to 1997 is primarily due to our California producing property acquisitions. Total upstream DD&A was $19.6 million, $25.6 million and $22.6 million in 1999, 1998 and 1997, respectively. On a per unit basis, DD&A was $2.13, $3.00 and $2.83 in 1999, 1998 and 1997, respectively. These amounts exclude the reduction in the carrying cost of our oil and natural gas properties in 1998. Midstream Results Gross margin from our midstream activities, excluding the unauthorized trading losses was $107.7 million, $38.4 million and $12.5 million for the years ended December 31, 1999, 1998 and 1997, respectively. An analysis of these results is discussed below. The following table sets forth certain of our midstream operating information for the periods presented (in thousands):
Year Ended December 31, ------------------------------------------------------------ 1999 1998 1997 ---------------- ---------------- ------------------ (restated) Operating Results: Gross margin Pipeline $ 56,864 $ 16,490 $ - Terminalling and storage and gathering and marketing 50,826 21,871 12,480 Unauthorized trading losses (166,440) (7,100) - --------------- ---------------- ----------------- Total (58,750) 31,261 12,480 General and administrative expense (23,599) (5,297) (3,529) -------------- --------------- ---------------- Gross profit $ (82,349) $ 25,964 $ 8,951 ============== =============== ================
41
Year Ended December 31, ------------------------------------------------------------ 1999 1998 1997 ---------------- ---------------- ------------------ (restated) Average Daily Volumes (barrels): Pipeline Activities: All American Tariff activities 101 113 - Margin activities 56 50 - Other 61 - - ---------------- ---------------- ------------------ Total 218 163 - ================ ================ ================== Lease gathering 239 88 71 Bulk purchases 138 98 49 ---------------- ---------------- ------------------ Total 377 186 120 ================ ================ ================== Terminal throughput 83 80 77 ================ ================ ================== Storage leased to third parties, monthly average volumes 1,975 1,150 668 ================ ================ ==================
Pipeline Operations. Gross margin from pipeline operations was $56.9 million for the year ended December 31, 1999, compared to $16.5 million for 1998. The increase resulted from twelve months of results from the All American Pipeline in 1999 versus five months in 1998, increased margins from our pipeline merchant activities, and to the 1999 acquisitions of Scurlock and the West Texas gathering system which contributed approximately $4.8 million of pipeline gross margin. The increase was partially offset by lower tariff transport volumes, due to lower production from Exxon's Santa Ynez Field and the Point Arguello Field, both offshore California. Volumes from these fields have steadily declined from 1995 through 1999. A 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline tariff revenues of approximately $2.6 million. The margin between revenue and direct cost of crude purchased was $33.5 million for the year ended December 31, 1999, compared to $3.9 million in 1998. Pipeline tariff revenues were approximately $46.4 million for the year ended December 31, 1999, compared to approximately $19.0 million in 1998. Pipeline operations and maintenance expenses were approximately $24.0 million for the year ended December 31, 1999, as compared to $6.1 million for 1998. Tariff transport volumes on the All American Pipeline decreased from an average of 113,000 barrels per day for the year ended December 31, 1998, to 101,000 barrels per day in 1999 due primarily to a decrease in shipments of offshore California production, which decreased from 90,000 barrels per day in 1998 to 79,000 barrels per day in 1999. Barrels associated with our merchant activities on the All American Pipeline increased from 50,000 barrels per day in 1998 to 56,000 barrels per day for the year ended December 31, 1999. Tariff volumes shipped on the Scurlock and West Texas Gathering systems averaged 61,000 barrels per day during 1999. In March 2000, we sold the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. We initiated the sale of approximately 5.2 million barrels of crude oil linefill from the All American Pipeline in November 1999. The sale of the linefill was substantially complete in February 2000. We estimate that we will recognize a total gain of approximately $44.6 million in connection with the sale of the linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. During 1999, we reported gross margin of approximately $5.0 million associated with operating the segment of the All American Pipeline that was sold. See Item 1. - "Business - Midstream Activities - Midstream Acquisitions and Dispositions". The following table sets forth the All American Pipeline average deliveries per day within and outside California from July 30, 1998, our date of acquisition (in thousands): Year Ended December 31, --------------------------- 1999 1998 --------- -------- Deliveries: Average daily volumes (barrels): Within California 101 111 Outside California 56 52 --------- -------- Total 157 163 ========= ======== 42 Gathering and Marketing Activities and Terminalling and Storage Activities. Excluding the unauthorized trading losses, gross margin from terminalling and storage and gathering and marketing activities was approximately $50.8 million for the year ended December 31, 1999, reflecting a 132% increase over the $21.9 million reported for 1998 and a 307% increase over the $12.5 million reported for 1997. The increase in gross margin is due to an increase in lease gathering and bulk purchase volumes, primarily as a result of the Scurlock acquisition, which contributed approximately $26.3 million of 1999 gross margin, and an increase in storage capacity leased at our Cushing Terminal. Lease gathering volumes increased from an average of 88,000 and 71,000 barrels per day in 1998 and 1997, respectively, to approximately 239,000 barrels per day in 1999. Bulk purchase volumes increased from approximately 98,000 and 49,000 barrels per day for 1998 and 1997, respectively, to approximately 138,000 barrels per day this year. Leased terminal capacity increased significantly from approximately 1.1 million barrels and 0.7 million barrels per month in 1998 and 1997, respectively, to 2.0 million barrels per month during 1999. The 1.1 million barrel expansion of our Cushing Terminal was placed in service in the second quarter of 1999. Throughput volumes at our terminals increased approximately 3,000 and 6,000 barrels per day in the current year period from 1998 and 1997, respectively. In the period immediately following the disclosure of the unauthorized trading losses, a significant number of PAA's suppliers and trading partners reduced or eliminated the open credit previously extended to PAA. Consequently, the amount of letters of credit PAA needed to support the level of crude oil purchases then in effect increased significantly. In addition, the cost to PAA of obtaining letters of credit increased under the amended credit facility. In many instances PAA arranged for letters of credit to secure its obligations to purchase crude oil from its customers, which increased its letter of credit costs and decreased its unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, certain of PAA's purchase contracts were terminated. As a result of these changes, aggregate volumes purchased are expected to decrease by 150,000 barrels per day, consisting primarily of lower unit margin purchases. Approximately 50,000 barrels per day of the decrease is related to barrels gathered at producer lease locations and 100,000 barrels per day is attributable to bulk purchases. As a result of the increase in letter of credit costs and reduced volumes, annual Adjusted EBITDA is expected to be adversely affected by approximately $5.0 million, excluding the positive impact of current favorable market conditions. Midstream General and Administrative. General and administrative expenses were $23.6 million for the year ended December 31, 1999, compared to $5.3 million and $3.5 million for 1998 and 1997, respectively. The increase from 1998 to 1999 was primarily attributable to the Scurlock acquisition in 1999 ($13.1 million), the All American Pipeline acquisition in 1998 ($0.7 million), expenses related to the operation of Plains All American Pipeline as a public entity ($0.7 million) and continued expansion of our midstream business activities. The increase in 1998 compared to 1997 is primarily due to the July 1998 All American Pipeline acquisition and expansion of our business activities. As a result of the unauthorized trading losses, we will incur increased expenses in 2000, primarily accounting and consulting related. Midstream Depreciation and Amortization. Depreciation and amortization expense was $17.4 million in 1999, $5.4 million in 1998 and $1.2 million in 1997. The increase in 1999 is due primarily to the Scurlock and West Texas Gathering System acquisitions in 1999 and the All American Pipeline acquisition in July 1998. The increase in 1998 is due to the All American Pipeline acquisition. Liquidity and Capital Resources General The financial loss resulting from the unauthorized trading activity placed PAA in default under certain of the covenants of its credit facilities and also created significant liquidity issues. In December 1999, PAA executed amended credit facilities and obtained default waivers from all of its lenders. In connection with the amendments, we loaned approximately $114.0 million to PAA. By May 2000 our liquidity was significantly improved through PAA's sales of the segment of the All American Pipeline and the related crude oil linefill for total proceeds of $224.0 million and the refinancing of PAA's credit facilities. Consolidated debt subsequent to the May 2000 refinancing was approximately $564.0 million, of which $256.0 million was reflected on the balance sheet as PAA debt. This balance compares to consolidated debt at December 31, 1999, of approximately $787.0 million, of which $369.0 million was PAA debt. In May 2000, PAA entered into two new credit facilities totaling $700.0 million. See "Credit Facilities." The new PAA facilities provide PAA with significant working capital availability, as well as flexibility for both internal and external growth opportunities. Giving effect to the repayment of existing debt and closing costs, PAA had approximately $256.0 million outstanding on its revolving credit facility as of May 8, 2000. Accordingly, PAA has approximately $144.0 million of additional borrowing capacity for acquisitions, capital expansion projects and general working capital purposes. In addition, the capacity available under the letter of credit facility should enable PAA to absorb additional acquisitions of other midstream assets and entities. 43 Subsequent to the refinancing and repayment to us of the intercompany loan, the balance outstanding on our $225.0 million revolving credit facility was approximately $28.0 million. This provides approximately $197.0 of liquidity to fund upstream working capital requirements, capital expenditures for 2000, as well as acquisition opportunities. The borrowing base under the revolving credit facility was reconfirmed by the lenders in the second quarter of 2000. We believe that we have sufficient liquid assets, cash from operations and borrowing capacity under our credit agreements to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures. Cash Flows
Year Ended December 31, ------------------------------------------------------------------- 1999 1998 1997 ------------------ ------------------- -------------------- (in millions) Cash provided by (used in): Operating activities $ (76.0) $ 37.6 $ 30.3 Investing activities (266.4) (483.4) (107.6) Financing activities 404.0 448.6 78.5
Operating Activities. Net cash used in operating activities in 1999 resulted from the unauthorized trading losses. The losses were partially offset by increased midstream margins due to the Scurlock and West Texas gathering system acquisitions and higher crude oil prices and increased volumes associated with our ongoing upstream acquisition and exploitation activities. Investing Activities. Net cash used in investing activities for 1999 included approximately $176.9 million for midstream acquisitions, primarily for the Scurlock and West Texas gathering system acquisitions, approximately $12.5 million for midstream capital costs and $77.9 for upstream acquisition, exploration, exploitation and development costs. Net cash used in investing activities for 1998 consisted primarily of approximately $394.0 million for the purchase of the All American Pipeline and SJV gathering system and $80.3 million for acquisition, exploration, exploitation and development costs. Financing activities. Cash provided by financing activities in 1999 was generated primarily from net issuances of (1) $50.0 million of Series F Preferred Stock (2) $50.8 million in PAA common units and (3) $325.2 million of short-term and long-term debt. In connection with the private placement sale of the Series F Preferred Stock, we agreed with the purchasers of the Series F Preferred Stock (who were also holders of the Series E Preferred Stock), to reduce the conversion price of the Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion price of the Series E Preferred Stock was effected through an exchange of each outstanding share of Series E Preferred Stock for a share of a new Series G Preferred Stock. Other than the reduction of the conversion price, the terms of the Series G Preferred Stock are substantially identical to those of the Series E Preferred Stock. In October 1999, PAA completed a public offering of an additional 2,990,000 common units, representing limited partner interests in PAA, at $18.00 per unit. Net proceeds to PAA from the offering, excluding our general partner contribution, were approximately $50.8 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. The proceeds were used to reduce outstanding debt. Approximately $44.0 million was used to prepay the term loan portion of the Plains Scurlock bank credit agreement and the remainder was used to reduce the balance outstanding on PAA's other revolving credit facility. Net issuances of debt include the sale of $75.0 million principal amount of Senior Subordinated Notes due 2006, Series E, bearing a coupon rate of 10.25%. The Series E Notes were issued pursuant to a Rule 144A private placement at approximately 101% of par. The stated coupon rate of interest and maturity date are the same as those of our existing $200.0 million principal amount of senior subordinated notes. Our net proceeds, after costs of the transaction, were approximately $74.6 million, and were used to reduce the outstanding balance on our revolving credit facility. See Note 7 to the consolidated financial statements. Financing activities for 1999 also included dividend payments of approximately $4.2 million on the Series E Preferred Stock and distributions to PAA unitholders of $22.2 million. 44 Cash provided by financing activities during 1998 included net issuances of (1) $138.8 million of short-term and long-term debt, (2) $241.7 million of common units in connection with PAA's initial public offering and (3) $85.0 million in preferred stock. Working Capital At December 31, 1999, we had working capital of approximately $115.9 million. Working capital at December 31, 1999 includes $37.9 million of pipeline linefill and $103.6 million for the segment of the All American Pipeline that were both sold in the first quarter of 2000. See Item 1. "Business - Midstream Activities - - Midstream Acquisitions and Dispositions." Proceeds from the linefill sale of approximately $100.0 million were used to repay short term working capital loans incurred in December 1999 and January 2000 and to fund the portion of the unauthorized trading losses that were settled in cash during the first quarter of 2000. Proceeds from the sale of the pipeline of approximately $129.0 million were used to reduce PAA's outstanding debt under its bank credit agreement. We had a working capital deficit of approximately $21.0 million at December 31, 1998. We have historically operated with a working capital deficit due primarily to ongoing capital expenditures that have been financed through cash flow and our revolving credit facility subsequently causing a timing difference between the expenditure and the payment. Capital Expenditures We have made and will continue to make substantial capital expenditures for the acquisition, exploitation, development, exploration and production of crude oil and natural gas reserves. Historically, we have financed these expenditures primarily with cash generated by operations, bank borrowings and the sale of subordinated notes, common stock and preferred stock. We intend to make aggregate capital expenditures of approximately $81.0 million in 2000, including approximately $72.0 million on the development and exploitation of our upstream properties, and approximately $9.0 million for midstream activities. In addition, we intend to continue to pursue the acquisition of underdeveloped producing properties. We believe that we will have sufficient cash from operating activities and borrowings under the revolving credit facility to fund our upstream capital expenditures. We plan to fund the midstream capital expenditures through working capital, cash flow and draws under PAA's revolving credit facility under its bank credit agreement. Commitments The aggregate amounts of maturities of all long-term indebtedness for the next five years based on balances outstanding subsequent to the May 2000 refinancing are: 2000 - $0.5 million, 2001 - $2.2 million, 2002 - $7.4 million, 2003 - $7.4 million, and 2004 - $263.4 million. These amounts consist principally of amounts due under our revolving credit facilities Historically, we have renewed and/or extended the revolving credit portion of our credit facilities prior to commencing scheduled payments. PAA will distribute 100% of its available cash within 45 days after the end of each quarter to unitholders of record, and to us. Available cash is generally defined as all cash and cash equivalents on hand at the end of the quarter less reserves established for future requirements. Minimum quarterly distributions are $0.45 for each full fiscal quarter. Distributions of available cash to the holders of subordinated units are subject to the prior rights of the holders of common units to receive the minimum quarterly distributions for each quarter during the subordination period, and to receive any arrearages in the distribution of minimum quarterly distributions on the common units for prior quarters during the subordination period. The expiration of the subordination period will generally not occur prior to December 31, 2003. There were no arrearages on common units at December 31, 1999. In connection with its crude oil marketing, PAA provides certain purchasers and transporters with irrevocable standby letters of credit to secure their obligation for the purchase of crude oil. Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 1999, PAA had outstanding letters of credit of approximately $321.5 million. Such letters of credit are secured by PAA's crude oil inventory and accounts receivable. Although we obtained environmental studies on our properties in California, the Sunniland Trend and Illinois Basin, and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for approximately 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. 45 Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks are approximately $13.4 million, net of salvage value and other considerations. Such estimated costs are amortized to expense through the unit-of-production method as a component of accumulated depreciation, depletion and amortization. Results from operations for 1999, 1998 and 1997 include $0.5 million, $0.8 million and $0.6 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected crude oil and natural gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in the accompanying Consolidated Financial Statements. As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows. Credit Facilities Amounts borrowed under our credit agreements before and after refinancing were as follows (in thousands):
December 31, May 8, 1999 2000 ---------------- ---------------- Revolving credit facility $ 137,300 $ 27,600 New Plains Marketing, L.P. revolving credit facility - 256,000 New Plains Marketing, L.P. letter of credit and hedged inventory facility - 20,250 PAA bank credit agreement 225,000 - Plains Scurlock bank credit agreement 85,100 - PAA letter of credit and borrowing facility 13,719 - PAA secured term credit facility 45,000 - ---------------- ---------------- $ 506,119 $ 303,850 ================ ================
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 December 31, 1999, 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, 2001, at which time the remaining outstanding balance converts to a term loan which is repayable in sixteen equal quarterly installments commencing October 1, 2001, 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 December 31, 1999, letters of credit of $0.6 million and borrowings of approximately $137.3 million were outstanding under 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 currently in compliance with the covenants in the revolving credit facility. Under the most restrictive of these covenants, at December 31, 1999, we could have borrowed the full $225.0 million available under the revolving credit facility. The unauthorized trading losses discovered in November 1999 resulted in a default of the covenants under PAA's credit facilities and significant short- term cash and letter of credit requirements. In December 1999, PAA executed amended credit facilities and obtained default waivers from all its lenders. PAA paid approximately $13.7 million in connection with the amended credit facilities. 46 On May 8, 2000, PAA entered into new bank credit agreements. The borrower under the new facilities is Plains Marketing, L.P., a subsidiary of PAA. 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 these subsidiaries; . refinance existing bank debt of All American Pipeline, L.P.; . repay to 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. At closing, PAA had $256.0 million outstanding under the 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. . 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 which 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 which 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 accounts receivable and accounts payable related to the purchase and sale of crude oil. At closing, there were letters of credit of approximately $173.8 million and borrowings of approximately $20.3 million outstanding under this 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 which 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 which 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. Under the most restrictive of these covenants, at May 8, 2000, PAA could have borrowed the full $400.0 million under its secured revolving credit facility. 47 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 in the Delaware Chancery Court 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 Item 3. - "Legal Proceedings." We may experience future releases of crude oil into the environment from our pipeline and storage operations, or discover releases that were previously unidentified. While we maintain an extensive inspection program designed to prevent and, as applicable, to detect and address such releases promptly, 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 benchmark NYMEX crude oil price of $25.60 per barrel at December 31, 1999 was more than double the $12.05 per barrel price at year-end 1998. Although we have routinely hedged a substantial portion of our crude oil production and intend to continue this practice, 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. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. In order to manage our exposure to commodity price risk, we have routinely hedged a portion of our crude oil production. For 2000, we have entered into various arrangements which provide for us to receive an average minimum NYMEX WTI price of $16.00 per barrel on 18,500 barrels of oil per day. Thus, based on our average fourth quarter 1999 crude oil production rate, these arrangements generally provide us with downside price protection for approximately 79% of our production. Approximately 10,000 barrels per day of the volumes hedged in 2000 will participate in price increases above the $16.00 per barrel floor price, subject to a ceiling limitation of $19.75 per barrel. For 2001, we have entered into various arrangements under which we will receive an average minimum NYMEX WTI price of approximately $19.00 per barrel on 12,000 barrels per day, which is equivalent to 51% of our fourth quarter 1999 crude oil production levels. Of these volumes, 100% have full market price participation up to $27.00 per barrel, 50% have price participation between $27.00 per barrel and $30.00 per barrel and 100% have full market price participation at prices above $30.00 per barrel. All of our NYMEX crude oil prices are before quality and location differentials. Because of the quality and location of our crude oil production, these adjustments will reduce our net price per barrel. 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. See Item 1. - "Business -- Product Markets and Major Customers" and Item 7a. - "Quantitative and Qualitative Disclosures About Market Risk". 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. A significant portion of the gross margin of PAA is derived from the Santa Ynez and Point Arguello fields located offshore California. Volumes received from the Santa Ynez and Point Arguello fields have declined from 92,000 and 60,000 average daily barrels, respectively, in 1995 to 59,000 and 20,000 average daily barrels, respectively, for the year ended December 31, 1999. We expect that there will continue to be natural production declines from each of these fields as the underlying reservoirs are depleted. As operator of Point Arguello, we are conducting additional drilling and other activities on this field, but we can not assure you that these activities will affect the production decline. A 5,000 barrel per day decline in volumes shipped from these fields would result in a decrease in annual pipeline tariff revenues of approximately $2.6 million. As previously discussed, our future results will also be affected by (1) natural decline in our producing oil and natural gas properties, (2) decreased gross margin due to the sale of the segment of the All American Pipeline (3) declines in offshore California production transported on the All American Pipeline and (4) reduced lease gathering and bulk purchase volumes and increased expenses resulting from the unauthorized trading losses. 48 Recent Accounting Pronouncements In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). 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 an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which 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. This statement was amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers the effective date of SFAS 133 to fiscal years beginning after June 15, 2000. We are required to adopt this statement beginning in 2001. We have not yet determined the effect that the adoption of SFAS 133 will have on our financial position or results of operations. Year 2000 Year 2000 Project. In order to address the Year 2000 issue, we initiated a Year 2000 project. We incurred approximately $2.1 million through December 31, 1999, in connection with our Year 2000 project, approximately $1.4 million of which were costs paid to third parties. We did not encounter any critical system application, hardware or equipment failures during the date roll over to the Year 2000, and have not experienced any disruptions of business activities as a result of Year 2000 failures by our customers, suppliers, service providers or business partners. Item 7a. 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, current economic conditions 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 purposes. 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 adverse price change are shown in the table below (in millions):
December 31, ---------------------------------------------------------------------------- 1999 1998 ------------------------------------- ---------------------------------- 10% 10% Adverse Adverse Fair Price Fair Price Value Change Value Change ----------------- --------------- --------------- --------------- Crude oil: Futures contracts $ - $ (2.8) $ 1.8 $ (0.3) Swaps and options contracts (22.0) (6.2) 16.9 (4.3)
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps are 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 year end. 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 adverse change 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. 49 Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for debt outstanding at December 31, 1999. Our variable rate debt bears interest at LIBOR plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 1999. The carrying value of variable rate bank debt approximates fair value as interest rates are variable, based on prevailing market rates. The fair value of fixed rate debt was based on quoted market prices based on trades of subordinated debt. The fair value of the Redeemable Preferred Stock approximates its liquidation value at December 31, 1999.
Expected Year of Maturity Fair -------------------------------------------------------------------------------- 2000 2001 2002 2003 2004 Thereafter Total Value -------------------------------------------------------------------------------- ------- (dollars in millions) Liabilities: Short-term debt - variable rate $ 58.7 $ - $ - $ - $ - $ - $ 58.7 $ 58.7 Average interest rate 8.74% 8.74% Long-term debt - variable rate 50.6 9.2 37.5 35.0 114.3 200.8 447.4 447.4 Average interest rate 8.44% 7.70% 7.76% 7.64% 8.63% 8.17% 8.23% Long-term debt - fixed rate 0.5 0.5 0.5 0.5 0.5 275.0 277.5 268.1 Average interest rate 8.00% 8.00% 8.00% 8.00% 8.00% 10.25% 10.23% Redeemable Preferred Stock - - - - - - $ 138.8 $ 138.8
At December 31, 1998, the carrying value of all variable rate bank debt and the Redeemable Preferred Stock of $184.7 million and $88.5 million, respectively, approximated the fair value and liquidation value, respectively, at that date. The carrying value and fair value of the fixed rate debt was $200.0 million and $202.0 million, respectively, at that date. 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 December 31, 1999, 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 $1.0 million as of such date. These instruments are based on LIBOR margins and generally provide for a floor of 5% and a ceiling of 6.5% for $90.0 million of debt and a floor of 6% and a ceiling of 8% for $125.0 million of debt. In August 1999, we terminated our swap arrangements on an aggregate notional principal amount of $175.0 million and we received consideration in the amount of approximately $10.8 million. At December 31, 1998, we had interest rate swap arrangements for an aggregate notional principal amount of $200.0 million and would have been required to pay approximately $3.3 million to terminate the instruments at that date. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required here is included in the report as set forth in the "Index to Financial Statements" on page F-1. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 50 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required here is included in the report as set forth in the "Index to Financial Statements" on page F-1. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding our directors will be included in the proxy statement for the 2000 annual meeting of stockholders (the "Proxy Statement") to be filed within 120 days after December 31, 1999, and is incorporated herein by reference. Information with respect to our executive officers is presented in Part I, Item 4 of this report. ITEM 11. EXECUTIVE COMPENSATION Information regarding executive compensation will be included in the Proxy Statement and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table lists the only persons who, to our knowledge, may be deemed to be beneficial owners, as of April 20, 2000 of more than 5% of the Company's Common Stock.
------------------------------------------------------------------------------------------------ Shares Beneficially Percent of Beneficial Owner Owned Class ------------------------------------------------------------------------------------------------ Advisory Research, Inc and David B. Heller 1,220,667 (1) 6.6% Two Prudential Plaza 180 N. Stetson, Suite 5780 Chicago, IL 60601 ------------------------------------------------------------------------------------------------ EnCap Energy Capital Fund III, L.P. 3,693,203 (2) 17.0% EnCap Energy Capital Fund III-B, L.P. Energy Capital Investment Company PLC BOCP Energy Partners, L.P. 1100 Louisiana St., Suite 3150 Houston, TX 77002 ------------------------------------------------------------------------------------------------ FMR Corp 1,038,400 (3) 5.8% 82 Devonshire Street Boston, MA 02109 ------------------------------------------------------------------------------------------------ Arthur E. Hall and Hallco Inc. 1,210,235 (4) 6.7% 1726 Cedarwood Drive Minden, NV 89423 ------------------------------------------------------------------------------------------------ KAIM Non-Traditional L.P and Richard A. Kayne 6,217,371 (5) 29.1% 1800 Avenue of the Stars, Second Floor Los Angeles, CA 90067 ------------------------------------------------------------------------------------------------ Schroder Capital Management, Inc. 954,600 5.31% 787 Seventh Avenue - 34/th/ Floor New York, NY 10019 ------------------------------------------------------------------------------------------------ Shell Land & Energy Company and Shell Oil Company 1,082,000 (6) 5.7% One Shell Plaza Houston, TX 77002 ------------------------------------------------------------------------------------------------ State Street Research & Management Company 1,804,258 (7) 10.0% One Financial Center, 30/th/ Floor Boston, MA 02111-2690 ------------------------------------------------------------------------------------------------ Strome Investment Management, L.P., 1,322,017 (8) 7.1% SSCO, Inc., and Mark E. Strome 100 Wilshire Blvd., Suite 1500 Santa Monica, CA 90401 ------------------------------------------------------------------------------------------------
_______________ (1) As reported on Schedule 13G filed on February 11, 2000, Advisory Research, Inc. and David B. Heller have shared voting and dispositive power for these shares. Includes 569,667 shares of Common Stock issuable upon conversion of shares of Series G Cumulative Convertible Preferred Stock ("Series G Preferred Stock"). David B. Heller is President and the controlling shareholder of Advisory Research, Inc. (2) Includes 1,774,836 shares issuable upon conversion of Series G Preferred Stock and 1,918,367 shares issuable upon conversion of Series F Cumulative Convertible Preferred Stock ("Series F Preferred Stock"). EnCap Investments L.L.C., a Delaware Corporation, serves as general partner for EnCap Energy Capital Fund III, L.P. and EnCap Energy Capital Fund III-B, L.P. In addition, EnCap Investments L.L.C. serves as Manager of BOCP Energy Partners, L.P. As such, EnCap Investments L.L.C. has sole discretion over investments made by these entities. The Managing Directors of EnCap Investments L.L.C. include Gary R. Petersen, Robert L. Zorich, D. Martin Phillips, and David B. Miller. Energy Capital Investment Company PLC has sole discretion over its own investments. The Board of Directors for Energy Capital Investment Company PLC consists of Peter Tudball (Chairman), Leo Deschuyteneer, Alan Henderson, James Ladner, Gary Petersen, and William Vanderfelt. (3) As reported on Schedule 13G filed February 14, 2000, FMR Corp. has sole voting power for 156,400 shares and sole dispositive power for 1,038,400 shares. As reported on Schedule 13G filed February 14, 2000, members of the Edward C. Johnson 3d family are the predominant owners of Class B shares of common stock of FMR Corp., representing approximately 49% of the voting power of FMR Corp. Mr. Johnson 3d owns 12.0% and Abigail Johnson owns 24.5% of the aggregate outstanding voting stock of FMR Corp. The Johnson family group and all other Class B shareholders have entered into a shareholders' voting agreement under which all Class B shares will be voted in accordance with the majority vote of Class B shares. Accordingly, through their ownership of voting common stock and the execution of the shareholders' voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR Corp. (4) Includes 58,570 shares issuable upon conversion of Series G Preferred Stock and 163,265 shares issuable upon conversion of Series F Preferred Stock. As reported on Schedule 13D filed on November 1, 1999, Valarian Associates, a Nevada limited partnership, Hallco, Inc., a Nevada corporation, A. E. Hall & Co. Money Purchase Plan (the "Plan") and Mr. Arthur E. Hall may be deemed to constitute a "group" within the meaning of Section 13(d)(3) of the Securities Exchange Act. Mr. Hall is (1) the sole general partner of Valarian, (2) the sole trustee and beneficiary of the Plan and (3) the President and controlling stockholder of Hallco. (5) As reported on Schedule 13D/A filed on December 15, 1999, KAIM Non- Traditional LP ("KAIM N-T, LP") and Mr. Kayne have shared voting and dispositive power for 5,897,574 shares held by investment partnerships and managed accounts. Mr. Kayne has sole voting and dispositive power for 319,797 shares which he holds individually. Total includes 101,350 shares of Common Stock issuable upon the exercise of a warrant, and 2,173,373 and 1,126,531 shares issuable upon conversion of shares of Series G Preferred Stock and Series F Preferred Stock, respectively. As reported on Schedule 13D/A filed on December 15, 1999, Kayne Anderson Investment Management, Inc. ("KAIM, Inc."), a Nevada corporation, serves as general partner of KAIM N-T, L.P. It serves as general partner of and investment adviser to six investment funds named Arbco Associates, L.P., Kayne Anderson Non- Traditional Investments, L.P., Offense Group Associates, L.P. and Opportunity Associates, L.P., each a California limited partnership and Kayne Anderson Energy Fund, L.P., Kayne Anderson Target Return Fund (QP), L.P., each a Delaware limited partnership. KAIM N-T, LP also serves as investment adviser to other clients, including Kayne Anderson Offshore Limited, a British Virgin Islands corporation. (6) Includes 932,000 shares issuable upon the conversion of Series D Cumulative Convertible Preferred Stock and 150,000 shares issuable upon the exercise of a warrant. As reported on Schedule 13D filed November 12, 1997, Shell Land & Energy Company, a Delaware corporation ("SLEC") is an indirect subsidiary of Shell Oil Company, a Delaware corporation ("Shell"). Shell is wholly-owned by Shell Petroleum Inc., a Delaware corporation, whose shares are directly or indirectly owned 60% by Royal Dutch Petroleum Company, The Hague, The Netherlands, and 40% by The "Shell" Transport and Trading Company, p.l.c., London, England. Royal Dutch Petroleum Company and The "Shell" Transport and Trading Company, p.l.c., are holding companies which together directly or indirectly own securities of companies of the Royal Dutch/Shell Group of Companies. (7) As reported on Schedule 13G filed April 5, 2000, filed by State Street Research & Management Company. According to such report, State Street had sole dispositive power for 1,804,258 shares and the sole voting power for 1,667,958 shares. State Street advised that all such shares are owned by various clients. (8) Includes 452,519 and 244,898 shares issuable upon conversion of shares of Series G Preferred Stock and Series F Preferred Stock, respectively. As reported on Schedule 13G filed on December 31, 1999, SSCO, Inc. is the sole general partner of Strome Investment Management, L.P. Mark E. Strome is the trustee of the trust that is the controlling shareholder of SSCO, Inc. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information regarding certain relationships and related transactions will be included in the Proxy Statement and is incorporated herein by reference. 51 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES See "Index to Consolidated Financial Statements" set forth on Page F-1. (a) (3) EXHIBITS 2.1 Stock Purchase Agreement dated as of March 15, 1998, among Plains Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven Inc. (incorporated by reference to Exhibit 2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997). 3.1 Second Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995). 3.2 Bylaws of the Company, as amended to date (incorporated by reference to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). 3.3 Certificate of Designation, Preference and Rights of Series D Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3(c) to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997). 3.4 Certificate of Designation, Preference and Rights of Series F Cumulative Convertible Preferred Stock. 3.5 Certificate of Designation, Preference and Rights of Series G Cumulative Convertible Preferred Stock. 4.1 Indenture dated as of March 15, 1996, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series A and Series B (incorporated by reference to Exhibit 4(b) to the Company's Form S-3 (Registration No. 333-1851)). 4.2 Indenture dated as of July 21, 1997, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series C and Series D (incorporated by reference to Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997). 4.3 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the Company's Form S-1 Registration Statement (Reg. No. 33-33986)). 4.4 Purchase Agreement for Stock Warrant dated May 16, 1994, between Plains Resources Inc. and Legacy Resources, Co., L.P. (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1994). 4.5 Warrant dated November 12, 1997, to Shell Land & Energy Company for the purchase of 150,000 shares of Common Stock (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1997). 4.6 Indenture dated as of September 15, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein and Chase Bank of Texas, National Association, as Trustee (incorporated by reference to Exhibit 4(a) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). 4.7 Registration Rights Agreement dated as of September 22, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein, J.P. Morgan Securities Inc. and First Union Capital Markets Corp. (incorporated by reference to Exhibit 4(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). 4.8 Stock Purchase Agreement dated as of December 15, 1999, among Plains Resources Inc. and the purchasers named therein. 4.9 Amendment to Stock Purchase Agreement dated as of December 17, 1999, among Plains Resources Inc. and the purchasers named therein. **10.1 Employment Agreement dated as of March 1, 1993, between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993). **10.2 The Company's 1991 Management Options (incorporated by reference to Exhibit 4.1 to the Company's Form S-8 Registration Statement (Reg. No. 33-43788)). **10.3 The Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 to the Company's Form S-8 Registration Statement (Reg. No. 33-48610)). **10.4 The Company's Amended and Restated 401(k) Plan (incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10.5 The Company's 1996 Stock Incentive Plan (incorporated by reference to Exhibit 4 to the Company's Form S-8 Registration Statement (Reg. No. 333-06191)). 52 **10.6 Stock Option Agreement dated August 27, 1996 between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(l) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10.7 Stock Option Agreement dated August 27, 1996 between the Company and William C. Egg Jr. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10.8 First Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996). **10.9 Second Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997). 10.10 Fourth Amended and Restated Credit Agreement dated May 22,1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(y) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1998) **10.11 First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(z) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998) **10.12 Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998) 10.13 First Amendment to Fourth Amended and Restated Credit Agreement dated as of November 17, 1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.14 Second Amendment to Fourth Amended and Restated Credit Agreement dated as of March 15, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). **10.15 Employment Agreement dated as of November 23, 1998, between Harry N. Pefanis and the Company (incorporated by reference to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998). 10.16 Purchase and Sale Agreement dated June 4, 1999, by and among the Company, Chevron U.S.A., Inc., and Chevron Pipe Line Company (incorporated by reference to Exhibit 10(h) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10.17 Third Amendment to Fourth Amended and Restated Credit Agreement dated June 21, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(p) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10.18 Second Amendment to Plains Resources 1996 Stock Incentive Plan dated May 20, 1999 (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999). 10.19 Fourth Amendment to Fourth Amended and Restated Credit Agreement dated September 15, 1999, among the Company and First Union National Bank, et al. (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999). 10.20 Fifth Amendment to Fourth Amended and Restated Credit Agreement dated December 1, 1999, among the Company and First Union National Bank, et al. 10.21 Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American, L.P.). 10.22 Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.04 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.). 10.23 Plains All American Inc., 1998 Management Incentive Plan Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.05 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.). 10.24 Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.). 10.25 Omnibus Agreement among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and Plains All American Inc. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.). 10.26 Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, file No. 333-64107 for Plains All American Pipeline, L.P.). 10.27 Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, file No. 333-64107 for Plains All American Pipeline, L.P.). 10.28 Form of Transaction Grant Agreement (Payment on Vesting) (incorporated by reference to Exhibit 10.12 to Registration Statement, file No. 333-64107 for Plains All American Pipeline, L.P.). 10.29 First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.). 10.30 Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit 10.31 Asset Sales Agreement between Chevron Pipe Line Company and Plains Marketing, L.P. dated as of April 16, 1999 (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999 for Plains All American Pipeline, L.P.). **10.32 Transaction Grant Agreement with Greg L. Armstrong (incorporated by reference to Exhibit 10.20 to Registration Statement on Form S-1, file no. 333-86907 1999 for Plains All American Pipeline, L.P.). 10.33 Pipeline Sale and Purchase Agreement dated January 31, 2000, among Plains All American Pipeline, L.P., All American Pipeline, L.P., El Paso Natural Gas Company and El Paso Pipeline Company (incorporated by reference to Exhibit 10.26 to Annual Report on Form 10-K for the Year Ended December 31, 1999 for Plains All American Pipeline, L.P.). 10.34 Credit Agreement [Letter of Credit and Hedged Inventory Facility] dated May 8, 2000, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders (incorporated by reference to Exhibit 10.01 to the Quarterly Report on Form 10-Q for Plains All American Pipeline, L.P. for the quarterly period ended March 31, 2000). 10.35 Credit Agreement [Revolving Credit Facility] dated May 8, 2000, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders (incorporated by reference to Exhibit 10.02 to the Quarterly Report on Form 10-Q for Plains All American Pipeline, L.P. for the quarterly period ended March 31, 2000). 21.1 Subsidiaries of the Company. *23.1 Consent of PricewaterhouseCoopers LLP. *27.1 Financial Data Schedule for the year ended December 31, 1999. ________________________ * Filed herewith ** A management contract or compensation plan. (b) REPORTS ON FORM 8-K A Current Report on Form 8-K was filed on November 29, 1999, regarding the discovery of unauthorized trading activity by a former employee of PAA, which was expected to result in losses to PAA of approximately $160.0 million. A Current Report on Form 8-K was filed on December 1, 1999, regarding the execution of agreements with PAA's lenders to provide for a $300.0 million credit facility and the waiver of defaults under certain covenants in its credit facilities which resulted from its unauthorized trading losses, as well as the execution by us of commitment letters for the sale of up to $50.0 million of a new series of preferred stock, the proceeds of which would constitute a portion of the $114.0 million in debt financing which we agreed to provide to PAA. 53 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PLAINS RESOURCES INC. Date: January 18, 2001 By: /s/ Phillip D. Kramer ------------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) 54 PLAINS RESOURCES INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Financial Statements Report of Independent Accountants.............................................................. F-2 Consolidated Balance Sheets as of December 31, 1999 and 1998................................... F-3 Consolidated Statements of Operations for the years ended December 31, 1999, 1998 and 1997..... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 1999, 1998 and 1997..... F-5 Consolidated Statements of Changes in Non-redeemable Preferred Stock, Common Stock and other Stockholders' Equity for the years ended December 31, 1999, 1998 and 1997.................... F-6 Notes to Consolidated Financial Statements..................................................... F-7
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. F-1 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Stockholders of Plains Resources Inc. In our opinion, the consolidated financial statements listed in the accompanying index, after the restatement described in Note 3, present fairly, in all material respects, the financial position of Plains Resources Inc. and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Houston, Texas March 29, 2000 F-2 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
DECEMBER 31, ---------------------------- 1999 1998 ---------- ---------- (RESTATED) ASSETS CURRENT ASSETS Cash and cash equivalents $ 68,228 $ 6,544 Accounts receivable and other 521,948 130,402 Inventory 40,478 42,520 Assets held for sale (Note 6) 141,486 - ---------- ---------- Total current assets 772,140 179,466 ---------- ---------- PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method Subject to amortization 671,928 596,203 Not subject to amortization 52,031 54,545 Crude oil pipeline, gathering and terminal assets 458,502 378,254 Other property and equipment 7,706 8,606 ---------- ---------- 1,190,167 1,037,608 Less allowance for depreciation, depletion and amortization (402,514) (375,882) ---------- ---------- 787,653 661,726 ---------- ---------- OTHER ASSETS 129,767 131,646 ---------- ---------- $1,689,560 $ 972,838 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 546,393 $ 190,246 Notes payable and other current obligations 109,880 10,261 ---------- ---------- Total current liabilities 656,273 200,507 BANK DEBT 137,300 52,000 BANK DEBT OF A SUBSIDIARY 259,450 175,000 SUBORDINATED DEBT 277,909 202,427 OTHER LONG-TERM DEBT 2,044 2,556 OTHER LONG-TERM LIABILITIES AND DEFERRED CREDITS 21,107 10,253 ---------- ---------- 1,354,083 642,743 ---------- ---------- COMMITMENTS AND CONTINGENCIES (NOTE 16) MINORITY INTEREST 156,045 172,438 ---------- ---------- CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 138,813 88,487 ---------- ---------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock, $1.00 par value, 46,600 shares authorized, issued and outstanding, net of discount of $1,354 at December 31, 1998 23,300 21,946 Common Stock, $0.10 par value, 50,000,000 shares authorized; issued and outstanding 17,924,050 and 16,881,938 shares at December 31, 1999 and 1998, respectively 1,792 1,688 Additional paid-in capital 130,027 124,679 Accumulated deficit (114,500) (79,143) ---------- ---------- 40,619 69,170 ---------- ---------- $1,689,560 $ 972,838 ========== ==========
See notes to consolidated financial statements. F-3 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except share data)
YEAR ENDED DECEMBER 31, ----------------------------------------------------------- 1999 1998 1997 ---------------- ----------------- -------------- (RESTATED) REVENUES Oil and natural gas sales $ 116,223 $ 102,754 $ 109,403 Marketing, transportation, storage and terminalling revenues 4,626,467 1,129,689 752,522 Gain on PAA unit offerings 9,787 60,815 - Gain on sale of linefill 16,457 - - Interest and other income 1,237 834 319 ---------- ---------- --------- 4,770,171 1,294,092 862,244 ---------- ---------- --------- EXPENSES Production expenses 55,645 50,827 45,486 Marketing, transportation, storage and terminalling expenses 4,518,777 1,091,328 740,042 Unauthorized trading losses and related expenses (Note 3) 166,440 7,100 - General and administrative 31,402 10,778 8,340 Depreciation, depletion and amortization 36,998 31,020 23,778 Reduction in carrying cost of oil and natural gas properties - 173,874 - Interest expense 46,378 35,730 22,012 ---------- ---------- --------- 4,855,640 1,400,657 839,658 ---------- ---------- --------- Income (loss) before income taxes, minority interest and extraordinary item (85,469) (106,565) 22,586 Minority interest (40,203) 786 - ---------- ---------- --------- Income (loss) before income taxes and extraordinary item (45,266) (107,351) 22,586 Income tax expense (benefit): Current (7) 862 352 Deferred (20,472) (45,867) 7,975 ---------- ---------- --------- Income (loss) before extraordinary item (24,787) (62,346) 14,259 Extraordinary item, net of tax benefit and minority interest (Note 12) (544) - - ---------- ---------- --------- NET INCOME (LOSS) (25,331) (62,346) 14,259 Less: cumulative preferred stock dividends 10,026 4,762 163 ---------- ---------- --------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (35,357) $ (67,108) $ 14,096 ========== ========== ========= Basic earnings per share: Income (loss) before extraordinary item $ (2.02) $ (3.99) $ 0.85 Extraordinary item (0.03) - - ---------- ---------- --------- Net income (loss) $ (2.05) $ (3.99) $ 0.85 ========== ========== ========= Diluted earnings per share: Income (loss) before extraordinary item $ (2.02) $ (3.99) $ 0.77 Extraordinary item (0.03) - - ---------- ---------- --------- Net income (loss) $ (2.05) $ (3.99) $ 0.77 ========== ========== =========
See notes to consolidated financial statements. F-4 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
YEAR ENDED DECEMBER 31, ---------------------------------------------------------- 1999 1998 1997 ---------------- ----------------- ------------- (RESTATED) CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (25,331) $ (62,346) $ 14,259 Items not affecting cash flows from operating activities: Depreciation, depletion and amortization 36,998 31,020 23,778 Reduction in carrying costs of oil and natural gas properties - 173,874 - Noncash gain (Notes 4 and 6) (26,244) (70,037) - Minority interest in income of a subsidiary (40,203) 786 - Deferred income taxes (20,472) (45,867) 7,975 Noncash compensation expense 1,013 - - Other noncash items (61) 90 221 Change in assets and liabilities from operating activities: Accounts receivable and other (226,438) 24,084 (9,390) Inventory 33,930 (19,057) (18,239) Pipeline linefill (3) (3,904) - Accounts payable and other current liabilities 171,974 8,987 11,703 Other long-term liabilities 18,873 - - ---------- ---------- --------- Net cash provided by (used in) operating activities (75,964) 37,630 30,307 ---------- ---------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Payments for midstream acquisitions (Note 6) (176,918) (394,026) - Payment for crude oil pipeline, gathering and terminal assets (12,507) (8,131) (923) Proceeds from the sale of oil and natural gas properties - 131 2,667 Payment for acquisition, exploration and developments costs (77,899) (80,318) (105,646) Payment for additions to other property and assets (2,472) (1,078) (3,732) Proceeds from sale of pipeline linefill (Note 6) 3,400 - - ---------- ---------- --------- Net cash used in investing activities (266,396) (483,422) (107,634) ---------- ---------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 744,971 570,560 266,905 Proceeds from short-term debt 131,119 31,750 39,000 Proceeds from sale of capital stock, options and warrants 5,542 828 1,104 Proceeds from issuance of preferred stock 50,000 85,000 - Proceeds from issuance of common units, net (Note 4) 50,759 241,690 - Principal payments of long-term debt (449,332) (423,560) (207,011) Principal payments of short-term debt (82,150) (40,000) (21,000) Costs incurred in connection with financing arrangements (19,448) (13,075) - Preferred stock dividends (4,245) - - Distributions to unitholders (22,201) - - Other (971) (4,571) (474) ---------- ---------- --------- Net cash provided by financing activities 404,044 448,622 78,524 ---------- ---------- --------- Net increase in cash and cash equivalents 61,684 2,830 1,197 Cash and cash equivalents, beginning of year 6,544 3,714 2,517 ---------- ---------- --------- Cash and cash equivalents, end of year $ 68,228 $ 6,544 $ 3,714 ========== ========== =========
See notes to consolidated financial statements. F-5 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (in thousands)
SERIES D CUMULATIVE ADDITIONAL ACCUMU- CONVERTIBLE PAID-IN LATED PREFERRED STOCK COMMON STOCK CAPITAL DEFICIT TOTAL -------------------------- --------------------- ----------- ----------- -------- SHARES AMOUNT SHARES AMOUNT ------------ ---------- --------- -------- Balance at December 31, 1996 - $ - 16,519 $ 1,652 $120,051 $ (26,131) $ 95,572 Capital stock issued upon exercise of options and other - - 184 18 1,936 - 1,954 Issuance of preferred stock and warrant in connection with an acquisition 47 20,508 - - 900 - 21,408 Amortization of discount 163 (163) - Net income for the year - - - - - 14,259 14,259 -------- --------- -------- -------- -------- --------- -------- Balance at December 31, 1997 47 20,671 16,703 1,670 122,887 (12,035) 133,193 Capital stock issued upon exercise of options and other - - 179 18 1,792 - 1,810 Issuance of preferred stock - - - - - - - Preferred stock dividends and amortization of discount - 1,275 - - - (4,762) (3,487) Net loss for the year (restated) - - - - - (62,346) (62,346) -------- --------- -------- -------- -------- --------- -------- Balance at December 31, 1998 (restated) 47 21,946 16,882 1,688 124,679 (79,143) 69,170 Capital stock issued upon exercise of options, warrants and other - - 943 94 3,583 - 3,677 Conversion of preferred stock into common stock - - 99 10 1,765 - 1,775 Preferred stock dividends and amortization of discount - 1,354 - - - (10,026) (8,672) Net loss for the year - - - - - (25,331) (25,331) -------- --------- -------- -------- -------- --------- -------- Balance at December 31, 1999 47 $ 23,300 17,924 $ 1,792 $130,027 $(114,500) $ 40,619 ======== ========= ======== ======== ======== ========= ========
See notes to consolidated financial statements. F-6 PLAINS RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 -- ORGANIZATION AND BASIS OF PRESENTATION Organization We are an independent energy company that is 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. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in Plains All American Pipeline, L.P. ("PAA"). 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. Basis of Consolidation and Presentation The consolidated financial statements include the accounts of Plains Resources Inc., our wholly-owned subsidiaries and 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 earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. All significant intercompany transactions have been eliminated. We have restated 1999 marketing, transportation, storage and terminalling revenues and expenses to appropriately reflect certain transactions between the upstream and midstream lines of business. Certain reclassifications have been made to the prior year statements to conform to the current year presentation. NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) crude oil and natural gas reserves (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and related valuation allowance and (4) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates. Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. Inventory. Crude oil inventory is carried at the lower of cost, as adjusted for deferred hedging gains and losses, or market value using an average cost method. Materials and supplies inventory is stated at the lower of cost or market with cost determined on a first-in, first-out method. Inventory consists of the following: DECEMBER 31, --------------------------- 1999 1998 ------- ------- (IN THOUSANDS) Crude oil $35,664 $37,702 Materials and supplies 4,814 4,818 ------- ------- $40,478 $42,520 ======= ======= Oil and Natural Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimate of future development and abandonment costs, net of salvage values and other considerations, are amortized to expense by the unit-of-production method using engineers' estimates of unrecovered proved oil and natural gas F-7 reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon (the "Standardized Measure") (see Note 20). Crude Oil Pipeline, Gathering and Terminal Assets. Crude oil pipeline, gathering and terminal assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives as follows: . crude oil pipelines - 40 years; . crude oil pipeline facilities - 25 years; . crude oil terminal and storage facilities - 30 to 40 years; . trucking equipment, injection stations and other - 5 to 10 years; and Acquisitions and improvements are capitalized; maintenance and repairs are expensed as incurred. Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to seven years. Other Assets. Other assets consist of the following (in thousands): DECEMBER 31, ------------------- 1999 1998 ------- ------- (RESTATED) Pipeline linefill $ 17,633 $ 54,511 Deferred tax asset (See Note 11) 67,366 46,356 Land 8,853 8,853 Debt issue costs 35,101 18,668 Other 10,965 8,245 -------- -------- 139,918 136,633 Accumulated amortization (10,151) (4,987) -------- -------- $129,767 $131,646 ======== ======== Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method. Debt issue costs at December 31, 1999 include approximately $13.7 million paid in the fourth quarter of 1999 to amend PAA's credit facilities as a result of defaults caused by unauthorized trading losses (see Note 3). Pipeline Linefill. Pipeline linefill is recorded at cost and consists of crude oil linefill used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location. After the sale of the linefill discussed below, we own approximately 1.2 million barrels of crude oil that is used to maintain the vast majority of our minimum operating linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated statements of cash flows. Proceeds from the sale of linefill in connection with the segment of the All American Pipeline that we sold are included in investing activities in the accompanying consolidated statements of cash flows (see Note 6). Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse. F-8 Revenue Recognition. Gathering and marketing revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to us, which typically occurs upon our receipt of the product. Terminalling and storage revenues are recognized at the time service is performed. Revenues for the transportation of crude oil are recognized based upon regulated and non-regulated tariff rates and the related transported volumes. Crude oil exchanges whereby like volumes are purchased and sold with the same customers with little effect on gross margin are reflected net and included in marketing, transportation, storage and terminalling expenses. We recognize oil and gas revenue from our interests in producing wells as oil and gas is produced and sold from those wells. Hedging. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and crude oil swap contracts entered into with financial institutions. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt. These derivative instruments qualify for hedge accounting as they reduce the price risk of the underlying hedged item and are designated as a hedge at inception. Additionally, the derivatives result in financial impacts which are inversely correlated to those of the items being hedged. This correlation, generally in excess of 80%, (a measure of hedge effectiveness) is measured both at the inception of the hedge and on an ongoing basis. If correlation ceases to exist, we would discontinue hedge accounting and apply mark to market accounting. Gains and losses on the termination of hedging instruments are deferred and recognized in income as the impact of the hedged item is recorded. Unrealized changes in the market value of crude oil hedge contracts are not generally recognized in our statement of operations until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in our statements of operations as a component of revenues. Such financial impacts are offset by gains or losses realized in the physical market. Cash flows from crude oil hedging activities are included in operating activities in the accompanying statements of cash flows. Net deferred gains and losses on futures contracts, including closed futures contracts, entered into to hedge anticipated crude oil purchases and sales are included in current assets or current liabilities in the accompanying balance sheets. Deferred gains or losses from inventory hedges are included as part of the inventory costs and recognized when the related inventory is sold. Amounts paid or received from interest rate swaps and collars are charged or credited to interest expense and matched with the cash flows and interest expense of the long-term debt being hedged, resulting in an adjustment to the effective interest rate. Deferred gains of $10.1 million received upon the termination of an interest rate swap are included in other long-term liabilities and deferred credits in the accompanying balance sheet at December 31, 1999. Stock Options. We have elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and related interpretations in accounting for our employee stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant. Sale of Units by a Subsidiary. When a subsidiary sells additional units to a third party, resulting in a change in our percentage ownership interest, we recognize a gain or loss in our consolidated statement of operations if the selling price per unit is more or less than our average carrying amount per unit. When we buy additional units from a subsidiary, resulting in a change in our percentage ownership interest, the difference between our cost and underlying equity in investee net assets is assigned first to identifiable tangible and intangible assets and to liabilities based on their fair values at the date of the change of interest; any unassigned difference is assigned to goodwill. Recent Accounting Pronouncements. In June 1998, the FASB issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"). 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 an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which 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. This statement was amended by Statement of Financial Accounting Standards No. 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133 ("SFAS 137") issued in June 1999. SFAS 137 defers the effective date of SFAS 133 to F-9 fiscal years beginning after June 15, 2000. We are required to adopt this statement beginning in 2001. We have not yet determined the effect that the adoption of SFAS 133 will have on our financial position or results of operations. 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). 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 from March through November 1999, and 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. As a result, we have restated our previously reported 1999 and 1998 results to reflect the losses incurred from these unauthorized trading activities. Approximately $7.1 million of the unauthorized trading losses were recognized in 1998 and the remainder in 1999. Normally, as it purchases crude oil, PAA establishes a margin by selling crude oil for physical delivery to third-party users or by entering into a future delivery obligation with respect to futures contracts. The employee in question violated PAA's policy of maintaining a position that is substantially balanced between crude oil purchases and sales or future delivery obligations. The unauthorized trading and associated losses resulted in a default of certain covenants under PAA's credit facilities and significant short-term cash and letter of credit requirements. Although one of our wholly-owned subsidiaries is the general partner of and owns 54% of PAA, the trading losses do not affect the operations or assets of our upstream business. The debt of PAA is nonrecourse to us. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities. Our $225.0 million credit facility is collateralized by our oil and natural gas properties. In December 1999, PAA executed amended credit facilities and obtained default waivers from all of its lenders. The amended credit facilities: . waived defaults under covenants contained in the existing credit facilities; . increased availability under PAA's letter of credit and borrowing facility from $175.0 million in November 1999 to $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000 and to $200.0 million in July 2000 through July 2001; . required the lenders' consent prior to the payment of distributions to unitholders; . prohibited contango inventory transactions subsequent to January 20, 2000; and . increased interest rates and fees under certain of the facilities. PAA paid approximately $13.7 million to its lenders in connection with the amended credit facilities. This amount was capitalized as debt issue costs and will be amortized over the remaining term of the amended facilities. In connection with the amendments, we loaned approximately $114.0 million to PAA. This subordinated debt is due not later than November 30, 2005. We financed the $114.0 million that we loaned PAA with: . the issuance of a new series of our 10% convertible preferred stock for proceeds of $50.0 million (see Note 8); . cash distributions of approximately $9.0 million made in November 1999 to PAA's general partner; and . $55.0 million of borrowings under our revolving credit facility. In the period immediately following the disclosure of the unauthorized trading losses, a significant number of PAA's suppliers and trading partners reduced or eliminated the open credit previously extended to PAA. Consequently, the amount of letters of credit PAA needed to support the level of its crude oil purchases then in effect increased significantly. In addition, the cost to PAA of obtaining letters of credit increased under the amended credit facility. In many instances PAA arranged for letters of credit to secure its obligations to purchase crude oil from its customers, which increased its letter of credit costs and decreased its unit margins. In other instances, primarily involving lower margin wellhead and bulk purchases, certain of its purchase contracts were terminated. F-10 The summarized restated results for the periods ended and financial position as of March 31, June 30, September 30, 1999 and December 31, 1998 are as follows (in thousands, except per shared data) (unaudited):
RESTATED -------------------------------------------------------------------------------- THREE PERIOD ENDED PERIOD ENDED MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 YEAR ENDED ---------------------- ----------------------- ENDED MARCH 31, THREE SIX THREE NINE DECEMBER 31, 1999 MONTHS MONTHS MONTHS MONTHS 1998 ------------ -------- ---------- ---------- ---------- ------------ OPERATIONS STATEMENT DATA: Revenues $476,971 $887,277 $1,364,248 $1,133,519 $2,497,767 $1,294,092 Operating profit (loss) 7,638 17,966 25,604 (21,624) 3,980 144,837 Net income (loss) (5,161) (3,116) (8,277) (20,047) (28,324) (62,346) Basic and diluted EPS (0.45) (0.33) (0.78) (1.30) (2.09) (3.99) BALANCE SHEET DATA: Current assets $193,752 $ 425,119 $ 539,296 $ 179,466 Current liabilities 215,879 474,017 642,767 200,507 Minority interest 166,647 162,276 132,869 172,438 Non-redeemable preferred stock, common stock and other stockholders' equity 65,908 60,983 46,050 69,170 CASH FLOW DATA: Net cash provided by operating activities $ 4,017 $ 25,742 $ 7,868 $ -
The summarized previously reported results for the periods ended and financial position as of March 31, June 30, September 30, 1999 and December 31, 1998 are as follows (in thousands, except per share data) (unaudited):
PREVIOUSLY REPORTED -------------------------------------------------------------------------------- THREE PERIOD ENDED PERIOD ENDED MONTHS JUNE 30, 1999 SEPTEMBER 30, 1999 YEAR ENDED ---------------------- ----------------------- ENDED MARCH 31, THREE SIX THREE NINE DECEMBER 31, 1999 MONTHS MONTHS MONTHS MONTHS 1998 ------------ -------- ---------- ---------- -------- ------------ STATEMENT OF OPERATIONS DATA: Revenues $476,971 $887,277 $1,364,248 $1,266,519 $2,630,767 $1,294,092 Operating profit 29,012 39,193 68,205 50,602 118,807 151,937 Net income 2,566 4,565 7,131 7,050 14,181 (58,554) Basic EPS 0.01 0.12 0.14 0.26 0.40 (3.77) Diluted EPS 0.01 0.11 0.13 0.24 0.37 (3.77) BALANCE SHEET DATA: Current assets $193,921 $ 425,045 $ 539,198 $ 179,466 Current liabilities 194,674 431,342 527,842 193,407 Minority interest 175,756 180,340 179,659 173,461 Non-redeemable preferred stock, common stock and other stockholders' equity 73,635 76,391 88,555 72,962 CASH FLOW DATA: Net cash provided by operating activities $ 3,848 $ 25,816 $ 7,966 $ -
Below is the summarized restated and previously reported results for the three and nine months ending September 30, 1998.
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, 1998 SEPTEMBER 30, 1998 ---------------------- --------------------- PREVIOUSLY PREVIOUSLY RESTATED REPORTED RESTATED REPORTED ---------- ---------- ---------- ---------- STATEMENT OF OPERATIONS DATA: Revenues $393,719 $393,719 $776,732 $776,732 Operating profit 20,111 27,111 55,968 62,968 Net income (loss) (1,442) 3,625 1,407 6,474 Basis EPS (0.19) 0.11 (0.06) 0.24 Diluted EPS (0.19) 0.10 (0.05) 0.22
NOTE 4 -- PLAINS ALL AMERICAN PIPELINE, L.P. - FORMATION AND OFFERINGS Our midstream activities are conducted through PAA. PAA was formed in September of 1998 to acquire and operate the business and assets of our wholly- owned midstream subsidiaries. On November 23, 1998, PAA completed an initial public offering of 13,085,000 common units at $20.00 per unit, representing limited partner interests and received proceeds of approximately $244.7 million. Concurrently with the closing F-11 of the initial public offering, we were merged with certain of our midstream subsidiaries, and then sold the assets of these subsidiaries to PAA in exchange for $64.1 million and the assumption of $11.0 million of related indebtedness. At the same time, the general partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System to PAA in exchange for: . 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2% general partner interest; . the right to receive incentive distributions as defined in the partnership agreement; and . PAA's assumption of $175.0 million of indebtedness incurred by the general partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System. In addition to the $64.1 million paid to us, PAA distributed approximately $177.6 million to the general partner and used approximately $3.0 million of the remaining proceeds to pay expenses incurred in connection with the offering. The general partner used $121.0 million of the cash distributed to it to retire the remaining indebtedness incurred in connection with the acquisition of the All American Pipeline and the SJV Gathering System and to pay other costs associated with the transactions. The general partner distributed the remaining $56.6 million to us, which we used to repay indebtedness and for other general corporate purposes. During 1998, we recognized a pre-tax gain of approximately $60.8 million (approximately $37.1 million after-tax) in connection with the formation of PAA. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of units in the initial public offering. The formation related expenses consist primarily of amounts due to certain key employees in connection with the successful formation of PAA, debt prepayment penalties and legal fees. In May 1999, PAA sold to the general partner 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.25 per unit, the price equal to the market value of PAA's common units on May 12, 1999, in connection with the Scurlock acquisition (see Note 6). In October 1999, PAA completed a public offering of an additional 2,990,000 common units representing limited partner interests, at $18.00 per unit. Net proceeds to PAA from the offering, including our general partner contribution of $0.5 million, were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. These proceeds were used to reduce outstanding debt. We recognized a pre-tax gain of $9.8 million ($6.0 million after-tax) in connection with the offering as a result of an increase in the book value of our equity in PAA, as discussed above. We held approximate interests of 59% and 54% before and after PAA's secondary offering, respectively. NOTE 5 -- UPSTREAM ACQUISITIONS AND DISPOSITIONS On July 1, 1999, Arguello Inc., our wholly owned subsidiary, acquired Chevron's interests in Point Arguello. The interests acquired include Chevron's 26% working interest in the Point Arguello Unit, its 26% interest in various partnerships owning the associated transportation, processing and marketing infrastructure, and Chevron's right to participate in surrounding leases and certain fee acreage onshore. We assumed its 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. Chevron retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities. Arguello Inc. is the operator of record for the Point Arguello Unit and has entered into an outsourcing agreement with a unit of Torch Energy Advisors, Inc. for the conduct of certain field operations and other professional services. During 1998, we acquired the Mt. Poso field from Aera Energy LLC for approximately $7.7 million. The field is located approximately 27 miles north of Bakersfield, California, in Kern County. The field added approximately 8 million barrels of oil equivalent to our proved reserves at the acquisition date. In March 1997, we completed the acquisition of Chevron's interest in the Montebello field for $25.0 million, effective February 1, 1997. The assets acquired consist of a 100% working interest and a 99.2% net revenue interest in 55 producing oil wells and related facilities and also include approximately 450 acres of surface fee land. At the acquisition date, the Montebello Field, which is located approximately 15 miles from our existing California operations, was producing approximately 800 barrels of crude oil and 800 Mcf of natural gas per day and added approximately 23 million barrels of oil equivalent to our proved reserves. The acquisition was funded with proceeds from our revolving credit facility. In November 1997, we acquired a 100% working interest and a 97% net revenue interest in the Arroyo Grande Field in San Luis Obispo County, California, from subsidiaries of Shell Oil Company ("Shell"). The assets acquired include surface F-12 and development rights to approximately 1,000 acres included in the 1,500 acre unit. At the acquisition date, the Arroyo Grande Field was producing approximately 1,600 barrels of 14 degrees API gravity crude oil per day from 70 wells and added approximately 20 million barrels of oil equivalent to our proved reserves. The aggregate purchase price of $22.1 million for the Arroyo Grande field consisted of rights to a non-producing property interest conveyed to Shell, the issuance of 46,600 shares of Series D Preferred Stock with an aggregate stated value of $23.3 million and a 5-year warrant to purchase 150,000 shares of Common Stock at $25.00 per share. No proved reserves had been assigned to the rights to the property interest conveyed. During 1997, we sold certain non-strategic crude oil and natural gas properties located primarily in Louisiana for net proceeds of approximately $2.7 million. NOTE 6 -- MIDSTREAM ACQUISITIONS AND DISPOSITIONS Scurlock Acquisition On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million. Scurlock, previously a wholly owned subsidiary of Marathon Ashland Petroleum, is engaged in crude oil transportation, gathering and marketing, and owns approximately 2,300 miles of active pipelines, numerous storage terminals and a fleet of more than 250 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Martin, Midland, Regan and Upton Counties, Texas. The assets we acquired also included approximately one million barrels of crude oil pipeline linefill. Financing for the Scurlock acquisition was provided through: . borrowings of approximately $92.0 million under Plains Scurlock's limited recourse bank facility with BankBoston, N.A.; . the sale to the general partner of 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of PAA's common units on May 12, 1999; and . a $25.0 million draw under PAA's existing revolving credit agreement. The funds for the purchase of the Class B units by the general partner were provided by a capital contribution from us. We financed our capital contribution through our revolving credit facility. The purchase price allocation was based on preliminary estimates of fair value and is subject to adjustment as additional information becomes available and is evaluated. The purchase accounting entries include a $1.0 million accrual for estimated environmental remediation costs. Under the agreement for the sale of Scurlock by Marathon Ashland Petroleum to Plains Scurlock, Marathon Ashland Petroleum has agreed to indemnify and hold harmless Scurlock and Plains Scurlock for claims, liabilities and losses resulting from any act or omission attributable to Scurlock's business or properties occurring prior to the date of the closing of such sale to the extent the aggregate amount of such losses exceed $1.0 million; provided, however, that claims for such losses must individually exceed $25,000 and must be asserted by Scurlock against Marathon Ashland Petroleum on or before May 15, 2003. The assets, liabilities and results of operations of Scurlock are included in our consolidated financial statements effective May 1, 1999. The Scurlock acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations ("APB 16") as follows (in thousands): Crude oil pipeline, gathering and terminal assets $125,120 Other property and equipment 1,546 Pipeline linefill 16,057 Other assets (debt issue costs) 3,100 Other long-term liabilities (environmental accrual) (1,000) Net working capital items (3,090) -------- Cash paid $141,733 ======== F-13 Pro Forma Results for the Scurlock Acquisition The following unaudited pro forma data is presented to show pro forma revenues, net loss and basic and diluted net loss per share as if the Scurlock acquisition, which was effective May 1, 1999, had occurred on January 1, 1998 (in thousands, except per share data): YEAR ENDED DECEMBER 31, ---------------------- 1999 1998 --------- ---------- (RESTATED) Revenues $5,153,046 $2,529,558 ========== ========== Net loss $ (27,147) $ (69,682) ========== ========== Net loss per share available to common stockholders: Basic and diluted $ (2.15) $ (4.43) ========== ========== West Texas Gathering System Acquisition On July 15, 1999, Plains Scurlock Permian, L.P. completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under the term loan portion of the Plains Scurlock credit facility. Venice Terminal Acquisition On September 3, 1999, PAA completed the acquisition of a Louisiana crude oil terminal facility and associated pipeline system from Marathon Ashland Petroleum LLC for approximately $1.5 million. The principal assets acquired include approximately 300,000 barrels of crude oil storage and terminalling capacity and a six-mile crude oil transmission system near Venice, Louisiana. All American Pipeline Acquisition On July 30, 1998, Plains All American Inc., acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot, a wholly-owned subsidiary of the Goodyear Tire and Rubber Company ("Goodyear") for approximately $400.0 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline and the SJV Gathering System, as well as other assets related to such operations. The acquisition was accounted for utilizing the purchase method of accounting with the assets, liabilities and results of operations included in our consolidated financial statements effective July 30, 1998. The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with APB 16 as follows (in thousands):
Crude oil pipeline, gathering and terminal assets $392,528 Other assets (debt issue costs) 6,138 Net working capital items (excluding cash received of $7,481) 1,498 -------- Cash paid $400,164 ========
Financing for the acquisition was provided through a $325.0 million, limited recourse bank facility and an approximate $114.0 million capital contribution by us. Actual borrowings at closing were $300.0 million. All American Pipeline Linefill Sale and Asset Disposition 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 substantially completed in February 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 F-14 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 for working capital purposes. We estimate that we will recognize a total gain of approximately $44.6 million in connection with the sale of linefill. As of December 31, 1999, we had delivered approximately 1.8 million barrels of linefill and recognized a gain of $16.5 million. 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. 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 total proceeds of $129.0 million. The proceeds from the sale were used to reduce PAA's outstanding debt. Our net proceeds are expected to be approximately $124.0 million, net of associated transaction costs and estimated costs to remove certain equipment. We estimate that we will recognize a gain of approximately $20.0 million in connection with the sale. During 1999, we reported gross margin of approximately $5.0 million from volumes transported on the segment of the line that was sold. The cost of the pipeline segment is included in assets held for sale on the consolidated balance sheet at December 31, 1999. NOTE 7 -- LONG-TERM DEBT AND CREDIT FACILITIES Short-term debt and current portion of long-term debt consists of the following (in thousands):
DECEMBER 31, ------------------------------- 1999 1998 --------- -------- PAA letter of credit and borrowing facility, bearing interest at weighted average interest rates of 8.7% and 6.8% at December 31, 1999 and 1998, respectively $ 13,719 $ 9,750 PAA secured term credit facility, bearing interest at a weighted average interest rate of 8.8% at December 31, 1999 45,000 - --------- -------- 58,719 9,750 Current portion of long-term debt 51,161 511 --------- -------- $ 109,880 $ 10,261 ========= ========
Long-term debt consists of the following (in thousands):
DECEMBER 31, ------------------------------- 1999 1998 --------- -------- Revolving credit facility, bearing interest at 7.6% and 6.9%, at December 31, 1999 and 1998, respectively $137,300 $ 52,000 PAA bank credit agreement, bearing interest at 8.3% and 6.8% at December 31, 1999 and 1998, respectively 225,000 175,000 Plains Scurlock bank credit agreement, bearing interest at 9.1% at December 31, 1999 85,100 - 10.25% Senior Subordinated Notes, due 2006, net of unamortized premium of $2.9 million and $2.4 million at December 31, 1999 and 1998, respectively 277,909 202,427 Other long-term debt 2,555 3,067 --------- -------- Total long-term debt 727,864 432,494 Less current maturities (51,161) (511) --------- -------- $ 676,703 $431,983 ========= ========
PLAINS RESOURCES LONG-TERM DEBT AND CREDIT FACILITIES Revolving Credit Facility 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 December 31, 1999, 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 F-15 time by the performance of our crude oil and natural gas properties and changes in crude oil and natural gas prices. We incur a commintment fee of 3/8% per annum on the unused portion of the borrowing base. The revolving credit facility, as amended, matures on July 1, 2001, at which time the remaining outstanding balance converts to a term loan which is repayable in sixteen equal quarterly installments commencing October 1, 2001, 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 December 31, 1999, letters of credit of $0.6 million and borrowings of approximately $137.3 million were outstanding under the revolving credit facility. The revolving credit facility contains covenants which, among other things, restrict the payment of cash dividends, 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. 10.25% Senior Subordinated Notes Due 2006 We have $275 million principal amount of 10.25% Senior Subordinated Notes Due 2006 outstanding which bear a coupon rate of 10.25% which at December 31, 1999 consists of (in thousands): Series A $ 500 Series B 149,500 Series C 50 Series D 49,950 Series E 75,000 -------- $275,000 ======== The Series A & B 10.25% Notes were issued in 1996 at 99.38% of par to yield 10.35%. The Series C & D 10.25% Notes were issued in 1997 at approximately 107% of par. Proceeds from the sale of the Series C & D 10.25% Notes, net of offering costs, were approximately $53.0 million and were used to reduce the balance on our revolving credit facility. The Series E 10.25% Notes were issued in September 1999 pursuant to a Rule 144A private placement at approximately 101% of par. Proceeds from the sale of the Series E 10.25% Notes, net of offering costs, were approximately $74.6 million and were used to reduce the balance on our revolving credit facility. In connection with the sale of the Series E Notes, we agreed to offer to exchange 10.25% Senior Subordinated Notes due 2006, Series F for all of the Series E Notes. The Series F Notes will be substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series E Notes except for certain transfer restrictions relating to the Series E Notes. We also agreed to file a registration statement with the SEC with respect to this exchange offer and to use our best efforts to cause such registration statement to be declared effective by January 20, 2000. If such registration statement is not declared effective by such date, with respect to the first 90- day period thereafter, the interest rate on the Series E Notes increases by 0.50% per annum and will increase by an additional 0.50% per annum with respect to each subsequent 90-day period until the registration statement has been declared effective, up to a maximum increase of 2% per annum. While the registration statement has been filed, we will not request the SEC to declare it effective until after the filing of our 1999 Form 10-K. As a result, the interest rate on the Series E Notes has increased to 10.75% for the 90-day period following January 20, 2000. At such time as the registration statement is declared effective by the SEC, the interest rate will revert to 10.25% per annum. The 10.25% Notes are redeemable, at our option, on or after March 15, 2001 at 105.13% of the principal amount thereof, at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100% of the principal amount thereof plus, in each case, accrued interest to the date of redemption. The Indenture contains covenants that include, but are not limited to, covenants that: (1) limit the incurrence of additional indebtedness; (2) limit certain investments; (3) limit restricted payments; (4) limit the disposition of assets; (5) limit the payment of dividends and other payment restrictions affecting subsidiaries; (6) limit transactions with affiliates; (7) limit the creation of liens; and (8) restrict mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, we will be required to make an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. F-16 The Series A-E Notes are unsecured general obligations and are subordinated in right of payment to all our existing and future senior indebtedness and are guaranteed by all of our upstream subsidiaries on a full, unconditional, joint and several basis. The Series A-E Notes are not guaranteed by PAA or any of our other midstream subsidiaries. PLAINS ALL AMERICAN PIPELINE L.P. CREDIT FACILITIES The discussion below relates to credit facilities of PAA, which are nonrecourse to us, but are included in our consolidated financial statements. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities. PAA has a 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 primarily to finance crude oil inventory which has been hedged against future price risk or designated as working inventory. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. As amended, the letter of credit facility has a sublimit for cash borrowings of $40.0 million at December 31, 1999, with decreasing amounts thereafter through April 30, 2000, at which time the sublimit is eliminated. The letter of credit and borrowing facility provides for an aggregate letter of credit availability of $295.0 million in December 1999, $315.0 million in January 2000, and thereafter decreasing to $239.0 million in February through April 2000, to $225.0 million in May and June 2000, and to $200.0 million in July 2000 through July 2001. 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 accounts receivable and accounts payable related to the purchase and sale of crude oil. This facility is secured by a lien on substantially all of PAA's assets except the assets which secure the Plains Scurlock credit facility. At December 31, 1999, there were letters of credit of approximately $292.0 million and borrowings of $13.7 million outstanding under this facility. On December 30, 1999, PAA entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility. At December 31, 1999, there were borrowings of $45.0 million outstanding. Concurrently with the closing of PAA's initial public offering in November 1998, PAA entered into a $225.0 million bank credit agreement that includes a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. The bank credit agreement is secured by a lien on substantially all of PAA's assets except the assets which secure the Plains Scurlock credit facility. PAA may borrow up to $50.0 million under the revolving credit facility for acquisitions, capital improvements, working capital and general business purposes. At December 31, 1999, PAA had $175.0 million outstanding under the term loan facility, and $50.0 million outstanding under the revolving credit facility. The term loan facility matures in 2005, and no principal is scheduled for payment prior to maturity. The term loan facility may be prepaid at any time without penalty. The revolving credit facility expires in November 2000. The term loan and revolving credit facility bear interest at PAA's option at either the base rate, as defined, plus an applicable margin, or reserve adjusted LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the revolving credit facility. Plains Scurlock, an operating partnership which is a subsidiary of PAA, has a bank credit agreement which consists of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The Plains Scurlock bank credit agreement is nonrecourse to PAA, Plains Marketing, L.P. and All American Pipeline, L.P. and is secured by substantially all of the assets of Plains Scurlock Permian, L.P. and its subsidiaries, including the Scurlock assets and the West Texas gathering system. Borrowings under the term loan and under the revolving credit facility bear interest at LIBOR plus the applicable margin. A commitment fee equal to 0.5% per year is charged on the unused portion of the revolving credit facility. The revolving credit facility, which may be used for borrowings or letters of credit to support crude oil purchases, matures in May 2002. The term loan provides for principal amortization of $0.7 million annually beginning May 2000, with a final maturity in May 2004. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. The term loan was reduced to $82.6 million from $126.6 million with proceeds from PAA's October 1999 public offering. F-17 All of PAA's credit facilities contain prohibitions on distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, PAA's facilities contain various covenants limiting its ability to: . incur indebtedness; . grant liens; . sell assets in excess of certain limitations; . engage in transactions with affiliates; . make investments; . enter into hedging contracts; and . enter into a merger, consolidation or sale of assets. Each of PAA's facilities treats a change of control as an event of default. In addition, the terms of PAA's letter of credit and borrowing facility and its bank credit agreement require lenders' consent prior to the payment of distributions to unitholders and require it to maintain: . a current ratio of 1.0 to 1.0, as defined in PAA's credit agreement; . a debt coverage ratio which is not greater than 5.0 to 1.0; . an interest coverage ratio which is not less than 3.0 to 1.0; . a fixed charge coverage ratio which is not less than 1.25 to 1.0; and . a debt to capital ratio of not greater than 0.60 to 1.0. The terms of the Plains Scurlock bank credit agreement require Plains Scurlock to maintain at the end of each quarter: . a debt coverage ratio of 6.0 to 1.0 from October 1, 1999 through June 30, 2000; 5.0 to 1.0 from July 1, 2000 through June 30, 2001; and 4.0 to 1.0 thereafter; and . an interest coverage ratio of 2.0 to 1.0 from October 1, 1999 through June 30, 2000 and 2.5 to 1.0 thereafter. In addition, the Plains Scurlock bank credit agreement contains limitations on the Plains Scurlock operating partnership's ability to make distributions to PAA if its indebtedness and current liabilities exceed certain levels as well as the amount of expansion capital it may expend. Maturities The aggregate amount of maturities of all long-term indebtedness for the next five years is: 2000 - $51.1 million, 2001 - $9.7 million, 2002 - $38.0 million, 2003 - $35.5 million and 2004 - $114.8 million. NOTE 8 - REDEEMABLE PREFERRED STOCK Liquidation Preference All series of our cumulative convertible preferred stock are stated at liquidation preference on the consolidated balance sheet. Liquidation preference represents the number of shares outstanding, which includes cumulative noncash dividends, multiplied by the stated value of the shares. Any unpaid cash dividends are accrued in accounts payable and other current liabilities on the consolidated balance sheet. We have no current intention of redeeming the cumulative preferred stock before its mandatory redemption date. However, we review our capital structure regularly and may redeem shares of our preferred stock if future conditions warrant. Series E and Series G Cumulative Convertible Preferred Stock On July 29, 1998, we sold in a private placement 170,000 shares of our Series E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock") for $85.0 million. Each share of the Series E Preferred Stock has a stated value of $500 per share and bears a dividend of 9.5% per annum. Dividends are payable semi-annually in either cash or additional shares of Series E Preferred Stock at our option and are cumulative from the date of issue. Each share of Series E Preferred Stock is convertible into 27.78 shares of common stock (an initial effective conversion price of $18.00 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any thirty-day trading period is equal to or greater than $21.60 per share. The Series E Preferred Stock is redeemable at our option at 105% of stated value through December 31, 2003 and at par thereafter. If not previously redeemed or converted, the Series E Preferred Stock is required to be redeemed in 2012. Proceeds from the Series E preferred Stock were used to fund a portion of our capital contribution to Plains All American Inc. to acquire the Celeron Companies (see Note 6). At December 31, 1999, these were 177,626 shares outstanding. On April 1, 1999, we paid a dividend on the Series E Preferred Stock for the period from October 1, 1998 through March 31, 1999. The dividend amount of approximately $4.1 million was paid by issuing 8,209 additional shares of the Series E Preferred Stock. On September 9, 1999, 3,408 shares of Series E Preferred Stock, including accrued dividends, were converted into 98,613 shares of common stock at a conversion price of $18.00 per share. On October 1, 1999, we paid a cash dividend of approximately $4.2 million on the Series E Preferred Stock for the period April 1, 1999 through September 30, 1999. F-18 In connection with the sale of the Series F Preferred Stock described below, we agreed with the purchasers of the Series F Preferred Stock (who were also holders of the Series E Preferred Stock), to reduce the conversion price of the Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion price of the Series E Preferred Stock was effected through an exchange of each outstanding share of Series E Preferred Stock for a share of a new Series G Preferred Stock. Other than the reduction of the conversion price, the terms of the Series G Preferred Stock are substantially identical to those of the Series E Preferred Stock. On March 22, 2000, our Board of Directors declared a cash dividend on our Series G Preferred Stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $4,219,000 is for the period of October 1, 1999 through March 31, 2000. Series F Cumulative Convertible Preferred Stock On December 14, 1999, we sold in a private placement 50,000 shares of our Series F Cumulative Convertible Preferred Stock (the "Series F Preferred Stock") for $50.0 million. Each share of the Series F Preferred Stock has a stated value of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable semi-annually in either cash or additional shares of Series F Preferred Stock at our option and are cumulative from the date of issue. Dividends paid in additional shares of Series F Preferred Stock are limited to an aggregate of six dividend periods. Each share of Series F Preferred Stock is convertible into 81.63 shares of common stock (an initial effective conversion price of $12.25 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any sixty-day trading period is equal to or greater than $21.60 per share. After December 15, 2003, the Series F Preferred Stock is redeemable at our option at 110% of stated value through December 15, 2004 and at declining amounts thereafter. If not previously redeemed or converted, the Series F Preferred Stock is required to be redeemed in 2007. At December 31, 1999, there were 50,000 shares outstanding. Proceeds from the Series F Preferred Stock were advanced to PAA in connection with the unauthorized trading losses through the issuance of $114.0 million of subordinated debt, due not later than November 30, 2005 (see Note 3). On March 22, our Board of Directors declared a cash dividend on our Series F Preferred Stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of approximately $1.5 million is for the period December 15, 1999 (the date of original issuance) through March 31, 2000. NOTE 9 -- CAPITAL STOCK Common and Preferred Stock We have authorized capital stock consisting of 50 million shares of common stock, $0.10 par value, and 2 million shares of preferred stock, $1.00 par value. At December 31, 1999, there were 17.9 million shares of common stock issued and outstanding and 274,226 shares of preferred stock outstanding. Stock Warrants and Options At December 31, 1999, we had warrants outstanding which entitle the holders thereof to purchase an aggregate 251,350 shares of common stock. Per share exercise prices and expiration dates for the warrants are as follows: 101,350 shares at $7.50 expiring in 2000 and 150,000 shares at $25.00 expiring in 2002. We have various stock option plans for our employees and directors (see Note 15). Series D Cumulative Convertible Preferred Stock In November 1997, we issued 46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D Preferred Stock"). The Series D Preferred Stock has an aggregate stated value of $23.3 million and is redeemable at our option at 140% of stated value. If not previously redeemed or converted, the Series D Preferred Stock will automatically convert into 932,000 shares of common stock in 2012. Each share of the Series D Preferred Stock has a stated value of $500 and is convertible into common stock at a ratio of $25.00 of stated value for each share of Common Stock to be issued. The Series D Preferred Stock was initially recorded at $20.5 million, a discount of $2.8 million from the stated value of $23.3 million. Commencing January 1, 2000, the Series D Preferred Stock will bear an annual dividend of $30.00 per share. Prior to this date, no dividends were accrued and the discount was amortized to retained earnings through December 31, 1999. On March 22, 2000, our Board of Directors declared a cash dividend on our Series D Preferred stock, which is payable on April 3, 2000 to holders of record on March 23, 2000. The dividend amount of $350,000 is for the period January 1, 2000 through March 31, 2000. F-19 NOTE 10 -- EARNINGS PER SHARE The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share computations for income (loss) from continuing operations before extraordinary item for the years ended December 31, 1999, 1998 and 1997 (in thousands, except per share amounts):
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------------------------- 1999 1998 (RESTATED) 1997 ---------------------------------- ------------------------------- ------------------------------ INCOME SHARES PER INCOME SHARES PER INCOME SHARES PER (NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE (NUMERA- (DENOMI- SHARE TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT TOR) NATOR) AMOUNT ------------- --------- -------- --------- --------- ------- -------- -------- -------- Income (loss) before extraordinary item $(24,787) $(62,346) $14,259 Less: preferred stock dividends (10,026) (4,762) (163) -------- -------- ------- Income (loss) available to common stockholders (34,813) 17,262 $(2.02) (67,108) 16,816 $(3.99) 14,096 16,603 $0.85 ====== ====== ===== Effect of dilutive securities: Employee stock options - - - - - 1,085 Warrants - - - - - 516 --------- ------ -------- ------ ------- ------ Income (loss) available to common stockholders assuming dilution $(34,813) 17,262 $(2.02) $(67,108) 16,816 $(3.99) $14,096 18,204 $0.77 ======== ====== ====== ======== ====== ====== ======= ====== =====
In 1999 and 1998, we recorded net losses and our options and warrants were not included in the computations of diluted earnings per share because their assumed conversion was antidilutive. In 1997 certain options and warrants to purchase shares of our common stock were not included in the computations of diluted earnings per share because the exercise prices were greater than the average market price of the common stock during the period of the calculations, resulting in antidilution. In addition, our preferred stock is convertible into common stock but was not included in the computation of diluted earnings per share in 1999, 1998 and 1997 because the effect was antidilutive. See Notes 9 and 15 for additional information concerning outstanding options and warrants. F-20 NOTE 11 -- INCOME TAXES Our deferred income tax assets and liabilities at December 31, 1999 and 1998, consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs incurred in both our upstream and midstream activities as follows (in thousands):
DECEMBER 31, --------------------------------------- 1999 1998 ---------------- ---------------- (restated) U.S. Federal - ------------ Deferred tax assets: Net operating losses $ 80,267 $48,911 Percentage depletion 2,450 2,450 Tax credit carryforwards 1,780 1,614 Excess outside tax basis over outside book basis 15,377 10,556 Other 627 1,268 -------- ------- 100,501 64,799 Deferred tax liabilities: Net oil & gas acquisition, exploration and development costs (28,788) (12,186) -------- ------- Net deferred tax asset 71,713 52,613 Valuation allowance (2,555) (2,786) -------- ------- 69,158 49,827 -------- ------- States - ------ Deferred tax liability (1,792) (3,471) -------- ------- Net deferred tax assets $ 67,366 $46,356 ======== =======
At December 31, 1999, we have a net deferred tax asset of $69.0 million, primarily attributable to net operating loss ("NOL") carryforwards. The minimum amount of future taxable income necessary to utilize the NOL carryforwards is $229.3 million. Based on current levels of pre-tax income, excluding nonrecurring items, management believes that it is more likely than not that we will generate taxable income from operations sufficient to realize the deferred tax asset. At December 31, 1999, we have carryforwards of approximately $229.3 million of regular tax NOLs, $7.0 million of statutory depletion, $1.4 million of alternative minimum tax credits and $0.3 million of enhanced oil recovery credits. At December 31, 1999, we had approximately $209.8 million of alternative minimum tax NOL carryforwards available as a deduction against future alternative minimum tax income. The NOL carryforwards expire from 2005 through 2019. Set forth below is a reconciliation between the income tax provision (benefit) computed at the United States statutory rate on income (loss) before income taxes and the income tax provision per the accompanying Consolidated Statements of Operations (in thousands):
YEAR ENDED DECEMBER 31, -------------------------------------------------------------- 1999 1998 1997 ---------------- ---------------- ---------------- (restated) U.S. federal income tax provision at statutory rate $(15,842) $(37,573) $7,905 State income taxes (1,298) (5,252) 376 Valuation allowance adjustment - (4,987) - Full cost ceiling test limitation (3,617) 2,903 - Other 278 (96) 46 -------- -------- ------ Income tax (benefit) on income before extraordinary item (20,479) (45,005) 8,327 Income tax benefit allocated to extraordinary item (293) - - -------- -------- ------ Income tax (benefit) provision $(20,772) $(45,005) $8,327 ======== ======== ======
F-21 In accordance with certain provisions of the Tax Reform Act of 1986, a change of greater than 50% of our beneficial ownership within a three-year period (an "Ownership Change") will place an annual limitation on our ability to utilize our existing tax carryforwards. Under the Final Treasury Regulations issued by the Internal Revenue Service, we do not believe that an Ownership Change has occurred as of December 31, 1999. NOTE 12 -- EXTRAORDINARY ITEM For the year ended December 31, 1999, we recognized a $1.5 million extraordinary loss ($0.5 million net of minority interest of $0.7 million and deferred tax benefit of $0.3 million) related to the early extinguishment of debt. The loss is related to the reduction of the Plains Scurlock term loan facility with proceeds from PAA's 1999 public offering and the restructuring of PAA's letter of credit and borrowing facility as a result of the unauthorized trading losses (see Note 3 and 7). NOTE 13 -- RELATED PARTY TRANSACTIONS Reimbursement of Expenses of the General Partner and Its Affiliates As the general partner for PAA, we have sole responsibility for conducting its business and managing its operations and we own all of the incentive distribution rights. Some of our senior executives who currently operate our business also manage the business of PAA. We do not receive any management fee or other compensation in connection with the management of their business, but we are reimbursed for all direct and indirect expenses incurred on their behalf. For the years ended December 31, 1999 and 1998, we were reimbursed approximately $44.7 million and $0.5 million, respectively, for direct and indirect expenses on their behalf. The reimbursed costs consist primarily of employee salaries and benefits. PAA does not employ any persons to manage its business. These functions are provided by the employees of the general partner and us. Crude Oil Marketing Agreement PAA is the exclusive marketer/purchaser for all of our equity crude oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity crude oil production for which they charge a fee of $0.20 per barrel. For the year ended December 31, 1999 and the period from November 23, 1998 to December 31, 1998, we were paid approximately $131.5 million and $4.1 million, respectively, for the purchase of crude oil under the agreement. Prior to the marketing agreement, PAA's predecessor marketed our crude oil production and that of our subsidiaries and our royalty owners. We were paid approximately $83.4 million and $101.2 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998 and the year ended December 31, 1997, respectively. In management's opinion, such purchases were made at prevailing market prices. PAA's predecessor did not recognize a profit on the sale of the crude oil purchased from us. Financing In December 1999, we loaned to PAA $114.0 million. This subordinated debt is due not later than November 30, 2005 (see Note 3). To finance a portion of the purchase price of the Scurlock acquisition, we purchased 1.3 million Class B common units from PAA at $19.125 per unit, the market value of the common units on May 12, 1999 (see Note 6). Long-Term Incentive Plans We have adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of the general partner and its affiliates who perform services for PAA. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of the general partner's board of directors. Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2000, an aggregate of approximately 500,000 restricted units have been authorized for grants to employees of the general partner, 170,000 of which have been granted with the remaining 330,000 to be granted in the near future. The Compensation Committee may, in the future, make additional grants under the plan to employees and directors containing such terms as the Compensation Committee shall determine. In general, restricted units granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of F-22 the subordinated units to common units. Grants made to non-employee directors of the general partner will be eligible to vest prior to termination of the subordination period. Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the Compensation Committee may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided. Transaction Grant Agreements In addition to the grants made under the Restricted Unit Plan described above, the general partner, at no cost to PAA, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key employees of the general partner. A grant covering 50,000 of such common units was terminated in 1999. Generally, approximately 69,444 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year equals or exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and the related distribution on the general partner interest. If a tranche of common units does not vest in a particular year, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 47,224 of the remaining common units vest in each of the years ending December 31, 1999, 2000 and 2001 if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distribution on all outstanding common units and subordinated units and the related distribution on the general partner interest. In 1999, approximately 69,444 of such common units vested and 47,224 of such common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as general partner prior to January 1, 2002. We recognized noncash compensation expense of approximately $1.0 million for the year ended December 31, 1999 related to the transaction grants which vested in 1999. This amount is included in general and administrative expense on the Consolidated Statements of Operations. NOTE 14 -- BENEFIT PLANS Effective June 1, 1996, our board of directors adopted a nonqualified retirement plan (the "Plan") for certain of our officers. Benefits under the Plan are based on salary at the time of adoption, vest over a 15-year period and are payable over a 15-year period commencing at age 60. The Plan is unfunded. Net pension expense for the years ended December 31, 1999, 1998 and 1997, is comprised of the following components (in thousands):
YEAR ENDED DECEMBER 31, ---------------------------------------------------------- 1999 1998 1997 ---------------- ---------------- ---------------- Service cost - benefits earned during the period $ 109 $ 97 $ 82 Interest on projected benefit obligation 83 74 60 Amortization of prior service cost 37 37 37 Unrecognized loss 6 3 - ---------------- ---------------- ---------------- Net pension expense $ 235 $ 211 $ 179 ================ ================ ================
F-23 Summarized information of our retirement plan for the periods indicated is as follows (in thousands):
December 31, ---------------------------- 1999 1998 ----------- ------------ Change in benefit obligation: Benefit obligation at beginning of year $ 1,280 $ 1,041 Service cost 109 97 Interest cost 83 74 Actuarial (gains) losses (239) 68 -------- -------- Benefit obligation at end of year $ 1,233 $ 1,280 ======== ======== Amounts recognized in the consolidated balance sheets: Projected benefit obligation for service rendered to date $ 1,233 $ 1,280 Plan assets at fair value - - -------- -------- Fair value of plan assets in excess of benefit obligation (1,233) (1,280) Unrecognized (gain) loss (34) 211 Unrecognized prior service costs 545 582 Adjustment to recognize minimum liability (512) (582) -------- -------- Net amount recognized $ (1,234) $ (1,069) ======== ========
The weighted-average discount rate used in determining the projected benefit obligation was 7.8% and 6.5% for the years ended December 31, 1999 and 1998. We also maintain a 401(k) defined contribution plan whereby we match 100% of an employee's contribution (subject to certain limitations in the plan), with matching contribution being made 50% in cash and 50% in common stock (the number of shares for the stock match being based on the market value of the common stock at the time the shares are granted). For the years ended December 31, 1999, 1998 and 1997, defined contribution plan expense was $1.0 million, $0.5 million and $0.4 million, respectively. NOTE 15 -- STOCK COMPENSATION PLANS Historically, we have used stock options as a long-term incentive for our employees, officers and directors under various stock option plans. The exercise price of options granted to employees is equal to or greater than the market price of the underlying stock on the date of grant. Accordingly, consistent with the provisions of APB 25, no compensation expense has been recognized in the accompanying financial statements. We have options outstanding under our 1996, 1992 and 1991 plans, under which a maximum of 3.5 million shares of common stock were reserved for issuance. Generally, terms of the options provide for an exercise price of not less than the market price of our stock on the date of the grant, a pro rata vesting period of two to four years and an exercise period of five to ten years. We have outstanding performance options to purchase a total of 500,000 shares of common stock which were granted to two executive officers. Terms of the options provide for an exercise price of $13.50, the market price on the date of grant, and an exercise period ending in August 2001. The performance options vest when the price of our common stock trades at or above $24.00 per share for any 20 trading days in any 30 consecutive trading day period or upon a change in control if certain conditions are met. F-24 A summary of the status of our stock options as of December 31, 1999, 1998, and 1997, and changes during the years ending on those dates are presented below:
1999 1998 1997 ------------------------- ------------------------- ------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE SHARES EXERCISE SHARES EXERCISE SHARES EXERCISE Fixed Options (000) PRICE (000) PRICE (000) PRICE - ------------- ---------- ------------ ----------- ----------- --------- -------------- Outstanding at beginning of year 2,749 $10.53 2,614 $ 9.50 2,435 $ 8.56 Granted 237 15.09 333 16.62 384 14.33 Exercised (158) 7.94 (179) 6.71 (163) 6.80 Forfeited (17) 9.93 (19) 11.36 (42) 9.82 ------- ------ ------ Outstanding at end of year 2,811 $11.06 2,749 $10.53 2,614 $ 9.50 ======= ====== ====== Options exercisable at year-end 1,836 $ 9.50 1,646 $ 8.53 1,494 $ 7.24 ======= ======= ====== Weighted-average fair value of options granted during the year $ 5.40 $ 4.93 $ 4.53
In October 1995, the Financial Accounting Standards Board issued SFAS 123 which established financial accounting and reporting standards for stock-based employee compensation. The pronouncement defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by APB 25. We have elected to follow APB 25 and related interpretations in accounting for our employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123 requires the use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense has been recognized in the accompanying financial statements. We will recognize compensation expense under APB 25 in the future for the performance options described above, if certain conditions are met and the options vest. Pro forma information regarding net income (loss) and earnings per share is required by SFAS 123 and has been determined as if we had accounted for our employee stock options under the fair value method as provided therein. The fair value for the options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for grants in 1999, 1998 and 1997: risk-free interest rates of 5.1% for 1999, 5.6% for 1998 and 6.1% for 1997; a volatility factor of the expected market price of our common stock of .50 for 1999, .38 for 1998 and .42 for 1997; no expected dividends; and weighted-average expected option lives of 2.7 years in 1999, 2.7 years in 1998 and 2.6 years in 1997. The Black-Scholes option valuation model and other existing models were developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of and are highly sensitive to subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not provide a reliable single measure of the fair value of its employee stock options. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The pro forma information is not meant to be representative of the effects on reported net income (loss) for future years, because as provided by SFAS 123, the effects of awards granted before December 31, 1994, are not considered in the pro forma calculations. Set forth below is a summary of our net income (loss) before extraordinary item and earnings per share as reported and pro forma as if the fair value based method of accounting defined in SFAS 123 had been applied (in thousands, except per share data). F-25
YEAR ENDED DECEMBER 31, ------------------------------------------------------------- 1999 1998 1997 ----------------- ----------------- ----------------- (RESTATED) AS REPORTED: Net income (loss) before extraordinary item $(25,331) $(62,346) $14,259 Net income (loss) per common share, basic (2.02) (3.99) 0.85 Net income (loss) per common share, diluted (2.02) (3.99) 0.77 PRO FORMA: Net income (loss) before extraordinary item $(25,669) $(63,054) $13,665 Net income (loss) per common share, basic (2.07) (4.03) 0.81 Net income (loss) per common share, diluted (2.07) (4.03) 0.74
The following table summarizes information about stock options outstanding at December 31, 1999 (share amounts in thousands):
WEIGHTED AVERAGE WEIGHTED WEIGHTED NUMBER REMAINING AVERAGE NUMBER AVERAGE RANGE OF OUTSTANDING CONTRACTUAL EXERCISE EXERCISABLE EXERCISE EXERCISE PRICE AT 12/31/99 LIFE PRICE AT 12/31/99 PRICE - -------------------- -------------- -------------- ------------- -------------- --------- $ 5.25 to $ 6.75 871 2.8 years $ 6.14 871 $ 6.14 7.50 to 7.81 345 3.4 years 7.64 336 7.64 10.50 to 15.63 1,420 2.3 years 14.02 454 13.95 17.00 to 19.19 175 3.8 years 18.31 175 18.31 ------ ------ $ 5.25 to $19.19 2,811 2.7 years $11.06 1,836 $ 9.50 ====== ======
NOTE 16 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION Commitments and Contingencies We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees whose contracts generally extend beyond one year but can be canceled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 1999, are summarized below (in thousands): 2000 $8,093 2001 5,759 2002 2,257 2003 1,595 2004 1,506 Later years 2,245 Total expenses related to these commitments for the years ended December 31, 1999, 1998 and 1997 were $9.3 million, $1.6 million and $1.1 million, respectively. In connection with its crude oil marketing, PAA provides certain purchasers and transporters with irrevocable standby letters of credit to secure their obligation for the purchase of crude oil. Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 1999, PAA had outstanding letters of credit of approximately $321.5 million. Such letters of credit are secured by PAA's crude oil inventory and accounts receivable. (see Note 7). Under the amended terms of an asset purchase agreement between us and Chevron, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 233. To the extent we elect not to plug and abandon the number of required wells, we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. As of December 31, 1999, we have not been required to make contributions to an escrow account. F-26 Although we obtained environmental studies on our properties in California, the Sunniland Trend and the Illinois Basin and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our California properties, we received a limited indemnity from Chevron for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties from Chevron, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties, there can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the Chevron indemnity. Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks is approximately $13.4 million, net of salvage value and other considerations. Such estimated costs are amortized to expense through the unit-of-production method as a component of accumulated depreciation, depletion and amortization. Results from operations for 1999, 1998 and 1997 include $0.5 million, $0.8 million and $0.6 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected crude oil and natural gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 20. As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved crude oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows. Industry Concentration Financial instruments which potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers of crude oil and natural gas products and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be reduced. The loss of an individual customer would not have a material adverse effect. There are a limited number of alternative methods of transportation for our production. Substantially all of our California crude oil and natural gas production and our Sunniland Trend crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our crude oil and natural gas production which could have a negative impact on future results of operations or cash flows. NOTE 17 -- LITIGATION 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, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the 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. Plaintiffs allege that the defendants are 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. The court has consolidated all subsequently filed cases under the first filed action described above. Two unopposed motions are currently pending to appoint lead plaintiffs. These motions ask the court to appoint two distinct lead plaintiffs to represent two different plaintiff classes: (1) purchasers of our common stock and options and (2) purchasers of PAA's common units. Once lead plaintiffs have been appointed, the plaintiffs will file their consolidated amended complaints. No answer or responsive pleading is due until thirty days after a consolidated amended complaint is filed. F-27 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 Plains All American Pipeline, L.P. and its unitholders by failing to monitor properly the activities of its employees. The derivative complaints allege, among other things, that Plains All American Pipeline has been harmed due to the negligence or breach of loyalty of the officers and directors that are named in the lawsuits. These cases are currently in the process of being consolidated. No answer or responsive pleading is due until these cases have been consolidated and a consolidated complaint has been filed. We intend to vigorously defend the claims made in the Texas securities 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 or results of operation. 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. We have reached an agreement in principle to settle with the Hughes Group. In consideration for full and final settlement, and dismissal with prejudice, we have agreed to pay to the Hughes Group the total sum of $100,000. We and Exxon have filed motions for summary judgment with respect to the claims of the remaining defendants. The court has not yet set a date for hearing of these motions. The trial date is currently scheduled in June 2000. We are a defendant, in the ordinary course of business, in various other legal proceedings in which our exposure, individually and in the aggregate, is not considered material to the accompanying financial statements. NOTE 18 -- FINANCIAL INSTRUMENTS Derivatives We utilize derivative financial instruments, as defined in Statement of Financial Accounting Standards No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments" to hedge our exposure to price volatility on crude oil and do not use such instruments for speculative trading purposes. These arrangements expose us to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where our purchases are less than expected. In the event of non-performance of a counterparty, we might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In order to minimize credit risk relating to the non-performance of a counterparty, we enter into such contracts with counterparties that are considered investment grade, periodically review the financial condition of such counterparties and continually monitor the effectiveness of derivative financial instruments in achieving our objectives. In view of our criteria for selecting counterparties, our process for monitoring the financial strength of these counterparties and our experience to date in successfully completing these transactions, we believe that the risk of incurring significant financial statement loss due to the non- performance of counterparties to these transactions is minimal. We have entered into various arrangements to fix the NYMEX crude oil spot price for a significant portion of our crude oil production. On December 31, 1999, these arrangements provided for a NYMEX crude oil price for 18,500 barrels per day from January 1, 2000, through December 31, 2000, at an average floor price of approximately $16.00 per barrel. Approximately 10,000 barrels per day of the volumes hedged in 2000 will participate in price increases above the $16.00 per barrel floor price, subject to a ceiling limitation of $19.75 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 F-28 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. At December 31, 1999, our hedging activities included crude oil futures contracts maturing in 2000 through 2002, covering approximately 7.4 million barrels of crude oil, including the portion of the linefill sold in January and February 2000. 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. In addition, we have entered into swap agreements with various financial institutions to hedge the interest rate on an aggregate of $240 million of bank debt. These swaps are scheduled to terminate in 2001 and thereafter. Fair Value of Financial Instruments The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments ("SFAS 107"). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgement is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Crude oil futures contracts permit settlement by delivery of the crude oil and, therefore, are not financial instruments, as defined. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):
DECEMBER 31, ------------------------------------------------------------- 1999 1998 -------------------------------- --------------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE ---------------- ------------- ------------ ------------ Long-Term Debt: Bank debt $396,750 $396,750 $227,000 $227,000 Subordinated debt 277,909 268,125 202,427 202,000 Other long-term debt 2,044 2,044 2,556 2,556 Redeemable Preferred Stock 138,813 138,813 88,487 88,487 OFF BALANCE SHEET FINANCIAL INFORMATION: Unrealized gain (loss) on crude oil swap and collar agreements (1) - (22,048) - 16,870 Unrealized gain (loss) on interest rate swap and collar agreements - 1,048 - (3,253)
(1) These amounts represent the calculated difference between the NYMEX crude oil price and the hedge arrangements for future production from our properties as of December 31, 1999 and 1998. These hedges, and therefore the unrealized gains or losses, have been included in estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 20. The carrying value of bank debt approximates its fair value as interest rates are variable, based on prevailing market rates. The fair value of subordinated debt was based on quoted market prices based on trades of subordinated debt. Other long-term debt was valued by discounting the future payments using our incremental borrowing rate. The fair value of the redeemable preferred stock is estimated to be its liquidation value at December 31, 1999 and 1998. The fair value of the interest rate swap and collar agreements is based on current termination values or quoted market prices of comparable contracts at December 31, 1999 and 1998. F-29 NOTE 19 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION Selected cash payments and noncash activities were as follows (in thousands):
YEAR ENDED DECEMBER 31, ------------------------------------------- 1999 1998 1997 ----------- ----------- ----------- Cash paid for interest (net of amount capitalized) $ 44,329 $ 34,546 $ 20,486 =========== =========== =========== Noncash sources and (uses) of investing and financing activities: Series D Preferred Stock dividends $ ( 1,354) $ (1,275) $ (163) =========== =========== =========== Exchange of preferred stock for common stock $ 71 $ - $ - =========== =========== =========== Series E Preferred Stock dividends $ (2,030) $ (3,487) $ - =========== =========== =========== Tax benefit from exercise of employee stock options $ 440 $ 653 $ 513 =========== =========== =========== Detail of properties acquired for other than cash: Fair value of acquired assets $ - $ - $ 22,140 Debt issued and liabilities assumed - - - Property exchanged - - (1,619) Capital stock and warrants issued - - (21,408) ----------- ----------- ----------- Cash (received) paid $ - $ - $ (887) =========== =========== ===========
NOTE 20 -- CRUDE OIL AND NATURAL GAS ACTIVITIES Our oil and natural gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands). Costs Incurred YEAR ENDED DECEMBER 31, ------------------------------- 1999 1998 1997 ------- -------- -------- Property acquisitions costs: Unproved properties $ 879 $ 6,266 $ 15,249 Proved properties 2,880 3,851 28,182 Exploration costs 4,101 1,657 1,730 Exploitation and development costs 65,119 89,161 82,217 ------- -------- -------- $72,979 $100,935 $127,378 ======= ======== ======== Capitalized Costs Under full cost accounting rules as prescribed by the Securities and Exchange Commission ("SEC"), unamortized costs of proved crude oil and natural gas properties are subject to a ceiling, which limits such costs to the Standardized Measure (as described below). At December 31, 1998, the capitalized costs of our proved crude oil and natural gas properties exceeded the Standardized Measure and we recorded a noncash, after tax charge to expense of $109.0 million ($173.9 million pre-tax). The following table presents the aggregate capitalized costs subject to amortization relating to our crude oil and natural gas acquisition, exploration, exploitation and development activities, and the aggregate related DD&A (in thousands). DECEMBER 31, -------------------- 1999 1998 --------- --------- Proved properties $ 671,928 $ 596,203 Accumulated DD&A (387,437) (369,260) --------- --------- $ 284,491 $ 226,943 ========= ========= The DD&A rate per equivalent unit of production excluding the writedown in 1998 was $2.13, $3.00 and $2.83 for the years ended December 31, 1999, 1998 and 1997, respectively. F-30 Costs Not Subject to Amortization The following table summarizes the categories of costs which comprise the amount of unproved properties not subject to amortization (in thousands). December 31, --------------------------------- 1999 1998 1997 ---------- ---------- ---------- Acquisition costs $ 42,261 $ 47,657 $ 41,652 Exploration costs 4,842 2,467 2,573 Capitalized interest 4,928 4,421 7,799 ---------- ---------- ---------- $ 52,031 $ 54,545 $ 52,024 ========== ========== ========== Unproved property costs not subject to amortization consist mainly of acquisition and lease costs and seismic data related to unproved areas. We will continue to evaluate these properties over the lease terms; however, the timing of the ultimate evaluation and disposition of a significant portion of the properties has not been determined. Costs associated with seismic data and all other costs will become subject to amortization as the prospects to which they relate are evaluated. Approximately 16%, 19% and 31% of the balance in unproved properties at December 31, 1999, related to additions made in 1999, 1998 and 1997, respectively. During 1999, 1998 and 1997, we capitalized $4.4 million, $3.7 million and $3.3 million, respectively, of interest related to the costs of unproved properties in the process of development. Supplemental Reserve Information (Unaudited) The following information summarizes our net proved reserves of crude oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the three years ended December 31, 1999. The following reserve information is based upon reports of the independent petroleum consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc., and Ryder Scott Company in 1999, 1998 and 1997 and in addition, in 1997 by System Technology Associates, Inc. The estimates are in accordance with regulations prescribed by the SEC. In management's opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 94% of year-end 1999 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility. Estimated Quantities of Crude Oil and Natural Gas Reserves (Unaudited) F-31 The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 1999 (in thousands).
As of or for the Year Ended December 31, ---------------------------------------------------------------------------- 1999 1998 1997 ------------------------- ------------------------- ------------------------ Oil Gas Oil Gas Oil Gas (Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf) ------------ ------------ ------------ ------------ ----------- ----------- Proved Reserves Beginning balance 120,208 86,781 151,627 60,350 115,996 37,273 Revision of previous estimates 62,895 (8,234) (46,282) 2,925 (16,091) 3,805 Extensions, discoveries, improved recovery and other additions 37,393 15,488 14,729 29,306 17,884 8,126 Sale of reserves in-place - - - (2,799) (26) (547) Purchase of reserves in-place 6,442 - 7,709 - 40,764 14,566 Production (8,016) (3,162) (7,575) (3,001) (6,900) (2,873) ------------ ------------ ------------ ------------ ----------- ----------- Ending balance 218,922 90,873 120,208 86,781 151,627 60,350 ============ ============ ============ ============ =========== =========== Proved Developed Reserves Beginning balance 73,264 58,445 99,193 38,233 86,515 25,629 ============ ============ ============ ============ =========== =========== Ending balance 120,141 49,255 73,264 58,445 99,193 38,233 ============ ============ ============ ============ =========== ===========
Standardized Measure of Discounted Future Net Cash Flows (Unaudited) The Standardized Measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is presented below (in thousands): December 31, -------------------------------------- 1999 1998 1997 ----------- ---------- ----------- Future cash inflows $ 4,837,010 $1,102,863 $ 2,237,876 Future development costs (231,914) (117,924) (157,877) Future production expense (1,758,572) (546,091) (1,019,254) Future income tax expense (845,133) - (261,130) ----------- ---------- ----------- Future net cash flows 2,001,391 438,848 799,615 Discounted at 10% per year (1,073,591) (211,905) (387,792) ----------- ---------- ----------- Standardized measure of discounted future net cash flows $ 927,800 $ 226,943 $ 411,823 =========== ========== =========== The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows: 1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions. 2. In accordance with SEC guidelines, the engineers' estimates of future net revenues from our proved properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. We have entered into various fixed price and floating price collar arrangements to fix or limit the NYMEX crude oil price for a significant portion of our crude oil production. Arrangements in effect at December 31, 1999 are reflected in the reserve reports through the term of the arrangements (see Note 18). The overall average prices used in the reserve reports as of December 31, 1999, were $20.94 per barrel of crude oil, condensate and natural gas liquids and $2.77 per Mcf of natural gas. 3. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs. 4. The reports reflect the pre-tax Present Value of Proved Reserves to be $1.2 billion, $226.9 million and $511.0 million at December 31, 1999, 1998 and 1997, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal F-32 income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards. The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 1999, are as follows (in thousands):
YEAR ENDED DECEMBER 31, ----------------------------------------- 1999 1998 1997 ----------- ---------- ---------- Balance, beginning of year $ 226,943 $ 411,823 $ 578,581 Sales, net of production expenses (60,578) (51,927) (63,917) Net change in sales and transfer prices, net of production expenses 580,890 (288,320) (359,138) Changes in estimated future development costs (52,951) 42,858 9,927 Extensions, discoveries and improved recovery, net of costs 112,573 21,095 84,676 Previously estimated development costs incurred during the year 22,842 25,501 23,449 Purchase of reserves in-place 53,724 14,173 74,278 Sales of reserves in-place - (1,151) (1,501) Revision of quantity estimates 404,705 (91,942) (57,597) Accretion of discount 22,694 51,099 76,477 Net change in income taxes (318,249) 99,170 87,024 Changes in estimated timing of production and other (64,793) (5,436) (40,436) ----------- ---------- ---------- Balance, end of year $ 927,800 $ 226,943 $ 411,823 =========== ========== =========
Results of Operations for Oil and Gas Producing Activities The results of operations from oil and gas producing activities excludes non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results.
Year Ended December 31, ------------------------------------------------ 1999 1998 1997 -------------- --------------- ------------- Revenues from oil and gas producing activities $ 116,223 $ 102,754 $ 109,403 Production costs (55,645) (50,827) (45,486) Depreciation, depletion and amortization (36,998) (31,020) (23,778) Reduction in carrying cost of oil and natural gas properties - (173,874) - Income tax (expense) benefit (9,196) 59,657 (15,654) ---------- ---------- ---------- Results of operations from producing activities (excluding corporate overhead and interest costs) $ 14,384 $ (93,310) $ 24,485 ========== ========== ==========
NOTE 21--QUARTERLY FINANCIAL DATA (UNAUDITED) The following table shows summary financial data for 1999 and 1998 (in thousands, except per share data):
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL --------------- -------------- -------------- ------------- --------------- 1999(1) - ------ Revenues $476,971 $887,277 $1,133,519 $2,262,617 $4,760,384 (2) Operating profit (loss) 7,638 17,966 (21,624) 15,542 19,522 (2) Net income (loss) (5,161) (3,116) (20,047) 2,993 (25,331) Basic and diluted EPS (0.45) (0.33) (1.30) 0.02 (2.05) 1998(1) - -------- Revenues $193,572 $189,441 $ 393,719 $ 456,545 (2) $1,233,277 (2) Operating profit 17,534 18,323 20,111 28,054 (2) 84,022 (2) Net income (loss) 1,431 1,418 (1,442) (63,753) (62,346) Basic EPS 0.07 0.07 (0.19) (3.92) (3.99) Diluted EPS 0.06 0.06 (0.19) (3.92) (3.99)
- ----------------- (1) As indicated in Note 3, quarterly results for 1999 and the fourth quarter of 1998 have been restated from amounts previously reported due to the unauthorized trading losses. (2) Excludes net gains of $9.8 million and $60.8 million related to PAA's unit offerings in 1999 and 1998, respectively, recorded upon the formation of PAA. F-33 NOTE 22--OPERATING SEGMENTS Our operations consist of three 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 assets and (3) Corporate - reflects certain amounts that are not directly attributable to Upstream or Midstream Operations. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 1). We evaluate segment performance based on gross margin, gross profit and income before income taxes and extraordinary items.
(IN THOUSANDS) UPSTREAM MIDSTREAM CORPORATE TOTAL - ---------------------------------------------------------------------------------------------------------------------------- (RESTATED) (RESTATED) 1999 Revenues: External customers $ 116,223 $4,626,467 $ - $4,742,690 Intersegment (a) - 75,454 - 75,454 Linefill gain - 16,457 - 16,457 Interest and other income 241 10,783 - 11,024 ----------- ------------- ---------- ------------ Total revenues of reportable segments $ 116,464 $4,729,161 $ - $4,845,625 =========== ============ ========= ============ Segment gross margin(b) $ 60,578 $ (58,750) $ - $ 1,828 Segment gross profit(c) 53,275 (82,349) (500) (29,574) Segment income (loss) before income taxes and extraordinary item 9,738 (93,601) (1,606) (85,469) Interest expense 23,586 21,686 1,106 46,378 Depreciation, depletion and amortization 19,586 17,412 - 36,998 Income tax expense (benefit) 1,635 18,844 - 20,479 Capital expenditures 77,899 189,286 - 267,185 Assets 445,921 1,243,639 - 1,689,560 - ---------------------------------------------------------------------------------------------------------------------------- 1998 Revenues: External customers $ 102,754 $1,129,689 $ - $1,232,443 Intersegment (a) - 119 - 119 Interest and other income 250 584 - 834 ----------- ------------- ---------- ------------ Total revenues of reportable segments $ 103,004 $1,130,392 $ - $1,233,396 =========== ============ ========= ============ Segment gross margin(b) (d) $ 51,927 $ 31,261 $ - $ 83,188 Segment gross profit(c) (d) 46,446 25,964 - 72,410 Segment income(loss) before income taxes and extraordinary item(d) (175,926) 8,546 - (167,380) Interest expense 23,099 12,631 - 35,730 Depreciation, depletion and amortization 199,523 5,371 - 204,894 Income tax expense (benefit) (33,732) (11,273) - (45,005) Capital expenditures 100,935 405,508 - 506,443 Assets 365,652 607,186 - 972,838 - ---------------------------------------------------------------------------------------------------------------------------- 1997 Revenues: External customers $ 109,403 $ 752,522 $ - $ 861,925 Intersegment (a) - - - - Interest and other income 181 138 - 319 ----------- ------------- ---------- ------------ Total revenues of reportable segments $ 109,584 $ 752,660 $ - $ 862,244 =========== ============ ========= ============ Segment gross margin(b) $ 63,917 $ 12,480 $ - $ 76,397 Segment gross profit(c) 59,106 8,951 - 68,057 Segment income before income taxes and extraordinary item 19,178 3,408 - 22,586 Interest expense 17,496 4,516 - 22,012 Depreciation, depletion and amortization 22,613 1,165 - 23,778 Income tax expense (benefit) 7,059 1,268 - 8,327 Capital expenditures 127,378 5,381 - 132,759 Assets 407,200 149,619 - 556,819 - ----------------------------------------------------------------------------------------------------------------------------
(a) Intersegment revenues and transfers were conducted on an arm's-length basis. (b) Gross margin is calculated as operating revenues less operating expenses. (c) Gross profit is calculated as operating revenues less operating expenses and general and administrative expenses. (d) Differences between segment totals and company totals represent the net gain of $60.8 million recorded upon the formation of PAA, which was not allocated to segments. F-34 The following table reconciles segment revenues to amounts reported in our financial statements:
FOR THE YEAR ENDED DECEMBER 31, ------------------------------------------------ 1999 1998 1997 ----------- ----------- ---------- Revenues of reportable segments $ 4,845,625 $ 1,233,396 $ 862,244 Intersegment (75,454) (119) - Net gain recorded upon the formation of PAA not allocated to reportable segments - 60,815 - ----------- ----------- ---------- Total company revenues $ 4,770,171 $ 1,294,092 $ 862,244 =========== =========== ==========
Customers accounting for more than 10% of total sales for the periods indicated are as follows: PERCENTAGE OF TOTAL SALES YEAR ENDED DECEMBER 31, ------------------------ CUSTOMER 1999 1998 1997 ------- ------ ------- Sempra Energy Trading Corporation 22% 27% 11% Koch Oil Company 18% 15% 27% PERCENTAGE OF OIL AND GAS SALES -------------------------------- Chevron 43% - - Tosco Refining Company 21% 50% - Conoco Inc. 12% Scurlock Permian LLC - 17% - Unocal Energy Trading, Inc. - - 52% Marathon Oil Company 17% - 23% Exxon Company U.S.A. - - 10% NOTE 23 -- 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 the Series A-E Notes discussed in Note 7 are not guaranteed by PAA and our consolidated financial statements include the accounts of PAA. F-35 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 - - - 277,909 OTHER LONG-TERM DEBT - 2,044 105,000 (105,000) 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 ----------- ------------ --------------- --------------- -------------- SERIES E, F AND G 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 =========== ============ =============== =============== ==============
F-36 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (restated) (in thousands) DECEMBER 31, 1998
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ------------- ------------- --------------- --------------- -------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 142 $ 194 $ 6,408 $ (200) $ 6,544 Accounts receivable and other 838 8,909 120,655 - 130,402 Inventory - 4,809 37,711 - 42,520 ------------- ------------- --------------- --------------- -------------- Total current assets 980 13,912 164,774 (200) 179,466 ------------- ------------- --------------- --------------- -------------- PROPERTY AND EQUIPMENT 234,127 424,646 378,835 - 1,037,608 Less allowance for depreciation, depletion and amortization (228,579) (91,118) (799) (55,386) (375,882) ------------- ------------- --------------- --------------- -------------- 5,548 333,528 378,036 (55,386) 661,726 ------------- ------------- --------------- --------------- -------------- INVESTMENTS IN SUBSIDIARIES AND INTERCOMPANY ADVANCES 246,581 (179,716) (2,847) (64,018) - OTHER ASSETS 47,435 8,177 76,034 - 131,646 ------------- ------------- --------------- --------------- -------------- $ 300,544 $ 175,901 $ 615,997 $ (119,604) $ 972,838 ============= ============= =============== =============== ============== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 18,425 $ 26,207 $ 145,814 $ (200) $ 190,246 Notes payable and other current obligations - 511 9,750 - 10,261 ------------- ------------- --------------- --------------- -------------- Total current liabilities 18,425 26,718 155,564 (200) 200,507 BANK DEBT 52,000 - - - 52,000 BANK DEBT OF A SUBSIDIARY - - 175,000 - 175,000 SUBORDINATED DEBT 202,427 - - - 202,427 OTHER LONG-TERM DEBT - 2,556 - - 2,556 OTHER LONG-TERM LIABILITIES 2,029 8,179 45 - 10,253 ------------- ------------- --------------- --------------- -------------- 274,881 37,453 330,609 (200) 642,743 ------------- ------------- --------------- --------------- -------------- MINORITY INTEREST (70,037) - 242,475 - 172,438 ------------- ------------- --------------- --------------- -------------- SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 88,487 - - - 88,487 ------------- ------------- --------------- --------------- -------------- NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY Series D Cumulative Convertible Preferred Stock 21,946 - - - 21,946 Common Stock 1,688 77 - (77) 1,688 Additional paid-in capital 124,679 3,954 38,727 (42,681) 124,679 Retained earnings (accumulated deficit) (141,100) 134,417 4,186 (76,646) (79,143) ------------- ------------- --------------- --------------- -------------- 7,213 138,448 46,671 (119,404) 69,170 ------------- ------------- --------------- --------------- -------------- $ 300,544 $ 175,901 $ 615,997 $ (119,604) $ 972,838 ============= ============= =============== =============== ==============
F-37 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (in thousands) YEAR ENDED DECEMBER 31, 1999
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ------------ ------------ ------------- ------------- -------------- (RESTATED) (RESTATED) REVENUES Crude oil and natural gas sales $ - $ 114,736 $ - $ 1,487 $ 116,223 Marketing, transportation, storage and terminalling - - 4,701,921 (75,454) 4,626,467 Gain on PAA unit offering - - 9,787 - 9,787 Gain on sale of linefill - 16,457 - 16,457 Interest and other income 699 89 996 (547) 1,237 ------------ ------------ ------------- ------------- -------------- 699 114,825 4,729,161 (74,514) 4,770,171 ------------ ------------ ------------- ------------- -------------- EXPENSES Production expenses - 55,645 - - 55,645 Marketing, transportation, storage and terminalling - - 4,592,744 (73,967) 4,518,777 Unauthorized trading loss and related expenses - - 166,440 166,440 General and administrative 2,311 5,492 23,599 - 31,402 Depreciation, depletion and amortization 2,096 17,490 17,412 - 36,998 Interest expense 6,994 18,851 21,080 (547) 46,378 ------------ ------------ ------------- ------------- -------------- 11,401 97,478 4,821,275 (74,514) 4,855,640 ------------ ------------ ------------- ------------- -------------- Income (loss) before income taxes, minority interest minority interest and extraordinary item (10,702) 17,347 (92,114) - (85,469) Minority interest - - (40,203) - (40,203) ------------ ------------ ------------- ------------- -------------- Income (loss) before income taxes (10,702) 17,347 (51,911) - (45,266) Income tax expense (benefit): Current (338) - 331 - (7) Deferred 3,457 (4,754) (19,175) - (20,472) ------------ ------------ ------------- ------------- -------------- Income (loss) before extraordinary item (13,821) 22,101 (33,067) - (24,787) Extraordinary item, net of tax benefit and minority interest - - (544) - (544) ------------ ------------ ------------- ------------- -------------- NET INCOME (LOSS) (13,821) 22,101 (33,611) - (25,331) Less: cumulative preferred stock dividends 10,026 - - - 10,026 ------------ ------------ ------------- ------------- -------------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (23,847) $ 22,101 $ (33,611) $ - $ (35,357) ============ ============ ============= ============= ==============
F-38 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (restated) (in thousands) YEAR ENDED DECEMBER 31, 1998
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ------------ ------------ ------------- ------------- -------------- REVENUES Crude oil and natural gas sales $ - $ 102,634 $ - $ 120 $ 102,754 Marketing, transportation, storage and terminalling - - 1,129,809 (120) 1,129,689 Gain on formation of PAA 60,815 - - - 60,815 Interest and other income 40 76 718 - 834 ------------ ------------ ------------- ------------- -------------- 60,855 102,710 1,130,527 - 1,294,092 ------------ ------------ ------------- ------------- -------------- EXPENSES Production expenses - 50,827 - - 50,827 Marketing, transportation, storage and terminalling - - 1,091,328 - 1,091,328 Unauthorized trading losses and related expenses - - 7,100 - 7,100 General and administrative 1,536 3,946 5,296 - 10,778 Depreciation, depletion and amortization 5,521 20,127 5,372 - 31,020 Reduction in carrying cost of oil and natural gas properties 9,267 25,738 - 138,869 173,874 Interest expense 11,389 11,710 12,631 - 35,730 ------------ ------------ ------------- ------------- -------------- 27,713 112,348 1,121,727 138,869 1,400,657 ------------ ------------ ------------- ------------- -------------- Income (loss) before income taxes and minority interest 33,142 (9,638) 8,800 (138,869) (106,565) Minority interest - - 786 - 786 ------------ ------------ ------------- ------------- -------------- Income (loss) before income taxes 33,142 (9,638) 8,014 (138,869) (107,351) Income tax expense (benefit): Current (3,637) (3) 4,502 - 862 Deferred (24,613) (9,237) (12,017) - (45,867) ------------ ------------ ------------- ------------- -------------- NET INCOME (LOSS) 61,392 (398) 15,529 (138,869) (62,346) Less: cumulative preferred stock dividends 4,762 - - - 4,762 ------------ ------------- ------------ ------------- -------------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ 56,630 $ (398) $ 15,529 $ (138,869) $ (67,108) ============ ============= ============ ============= ==============
F-39 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (in thousands) YEAR ENDED DECEMBER 31, 1997
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ----------- ------------- -------------- ------------ -------------- REVENUES Crude oil and natural gas sales $ 867 $ 108,536 $ - $ - $ 109,403 Marketing, transportation, storage and terminalling - - 752,522 - 752,522 Interest and other income 90 91 138 - 319 ----------- ------------ -------------- ------------ -------------- 957 108,627 752,660 - 862,244 ----------- ------------ -------------- ------------ -------------- EXPENSES Production expenses 282 45,204 - - 45,486 Marketing, transportation, storage and terminalling - 9 740,033 - 740,042 General and administrative 1,294 3,517 3,529 - 8,340 Depreciation, depletion and amortization 5,887 16,741 1,150 - 23,778 Interest expense 10,111 7,384 4,517 - 22,012 ----------- ------------ -------------- ------------ -------------- 17,574 72,855 749,229 - 839,658 ----------- ------------ -------------- ------------ -------------- Income (loss) before income taxes (16,617) 35,772 3,431 - 22,586 Income tax expense (benefit): Current (507) 792 67 - 352 Deferred 5,328 1,450 1,197 - 7,975 ----------- ------------ -------------- ------------ -------------- NET INCOME (LOSS) (21,438) 33,530 2,167 - 14,259 Less: cumulative preferred stock dividends 163 - - - 163 ----------- ------------ -------------- ------------ -------------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (21,601) $ 33,530 $ 2,167 $ - $ 14,096 =========== ============ ============== ============ ==============
F-40 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (in thousands) YEAR ENDED DECEMBER 31, 1999
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ----------- ------------- -------------- ------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $(13,821) $ 22,101 $ (33,611) $ - $ (25,331) Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, and amortization 2,096 17,490 17,412 - 36,998 Noncash gains (Note 4 and 6) - - (26,244) - (26,244) Minority interest in income of a subsidiary - - (40,203) - (40,203) Deferred income tax 3,457 (4,754) (19,175) - (20,472) Noncash compensation expense - - 1,013 - 1,013 Other noncash items (1,108) - 1,047 - (61) Change in assets and liabilities resulting from - operating activities: - Accounts receivable and other (970) (1,287) (224,181) - (226,438) Inventory - (842) 34,772 - 33,930 Pipeline linefill - - (3) - (3) Accounts payable and other current liabilities 5,275 2,169 164,530 - 171,974 Other long-term liabilities - - 18,873 - 18,873 ----------- ------------- -------------- ------------- -------------- NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES (5,071) 34,877 (105,770) - (75,964) ----------- ------------- -------------- ------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES Payments for midstream acquisitions (See Note 6) - - (176,918) - (176,918) Payments for crude oil pipeline, gathering - and terminal assets - - (12,507) - (12,507) Payments for acquisition, exploration, - and development costs (3,793) (74,106) - - (77,899) Payments for additions to other property and assets (267) (2,137) (68) - (2,472) Proceeds from sale of pipeline linefill - - 3,400 - 3,400 ----------- ------------- -------------- ------------- -------------- NET CASH USED IN INVESTING ACTIVITIES (4,060) (76,243) (186,093) - (266,396) ----------- ------------- -------------- ------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES Advances/investments with affiliates (194,902) 46,306 148,396 200 - Proceeds from long-term debt 341,250 - 403,721 - 744,971 Proceeds from short-term debt - - 131,119 - 131,119 Proceeds from sale of capital stock, - options and warrants 5,542 - - - 5,542 Proceeds from issuance of preferred stock 50,000 - - - 50,000 Proceeds from issuance of common units (Note 4) (25,000) - 75,759 - 50,759 Principal payments of long-term debt (180,711) - (268,621) - (449,332) Principal payments of short-term debt - - (82,150) - (82,150) Costs incurred in connection with - financing arrangements (2,205) - (17,243) - (19,448) Preferred stock dividends (4,245) - - - (4,245) Distribution to unitholders 29,472 - (51,673) - (22,201) Other (971) - - - (971) ----------- ------------- -------------- ------------- -------------- NET CASH PROVIDED BY FINANCING ACTIVITIES 18,230 46,306 339,308 200 404,044 ----------- ------------- -------------- ------------- -------------- Net increase in cash and cash equivalents 9,099 4,940 47,445 200 61,684 Cash and cash equivalents, beginning of period 142 194 6,408 (200) 6,544 ----------- ------------- -------------- ------------- -------------- Cash and cash equivalents, end of period $ 9,241 $ 5,134 $ 53,853 $ - $ 68,228 =========== ============= ============== ============= ==============
F-41 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (restated) (in thousands) YEAR ENDED DECEMBER 31, 1998
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ----------- ------------ ------------- ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 61,392 $ (398) $ 15,529 $ (138,869) $ (62,346) Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 5,521 20,127 5,372 - 31,020 Reduction in carrying costs of oil and natural gas properties 9,267 25,738 - 138,869 173,874 Noncash gain (Note 4 and 6) (70,037) - - - (70,037) Minority interest in income of a subsidiary - - 786 - 786 Deferred income tax (24,613) (9,237) (12,017) - (45,867) Other noncash items 90 - - - 90 Change in assets and liabilities resulting from operating activities: Accounts receivable and other 275 (3,444) 27,253 - 24,084 Inventory 8 (924) (18,141) - (19,057) Pipeline linefill - - (3,904) - (3,904) Accounts payable and other current liabilities 6,232 (10,782) 10,825 2,712 8,987 ----------- ------------ ------------- ------------- ------------- NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES (11,865) 21,080 25,703 2,712 37,630 ----------- ------------ ------------- ------------- ------------- CASH FLOWS FROM INVESTING ACTIVITIES Payments for midstream acquisitions (Note 6) - - (394,026) - (394,026) Payments for crude oil pipeline, gathering and terminal assets - - (8,131) - (8,131) Proceeds from the sale of oil and natural gas properties - 131 - - 131 Payments for acquisition, exploration, and development costs - (80,318) - - (80,318) Payments for additions to other property and other assets (510) (309) (259) - (1,078) ----------- ------------ ------------- ------------- ------------- NET CASH USED IN INVESTING ACTIVITIES (510) (80,496) (402,416) - (483,422) ----------- ------------ ------------- ------------- ------------- CASH FLOWS FROM FINANCING ACTIVITIES Advances/investments with affiliates (54,060) 59,347 (5,287) - - Proceeds from long-term debt 239,260 - 331,300 - 570,560 Proceeds from short-term debt - - 31,750 - 31,750 Proceeds from sale of capital stock, options and warrants 828 - - - 828 Proceeds from issuance of preferred stock 85,000 - - - 85,000 Proceeds from issuance of common units - - 241,690 - 241,690 Distributions upon formation 241,690 - (241,690) - - Principal payments of long-term debt (384,260) - (39,300) - (423,560) Principal payments of short-term debt - - (40,000) - (40,000) Capital contribution from Parent (113,700) - 113,700 - - Dividend to Parent 3,557 - (3,557) - - Costs incurred in connection with financing arrangements (6,138) - (6,937) - (13,075) Other (4,571) - - - (4,571) ----------- ------------ ------------- ------------- ------------- NET CASH PROVIDED BY FINANCING ACTIVITIES 7,606 59,347 381,669 - 448,622 ----------- ------------ ------------- ------------- ------------- Net increase (decrease) in cash and cash equivalents (4,769) (69) 4,956 2,712 2,830 Cash and cash equivalents, beginning of period 4,911 263 1,452 (2,912) 3,714 ----------- ------------ ------------- ------------- ------------- Cash and cash equivalents, end of period $ 142 $ 194 $ 6,408 $ (200) $ 6,544 =========== ============ ============= ============= =============
F-42 PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (unaudited) (in thousands) YEAR ENDED DECEMBER 31, 1997
Guarantor Nonguarantor Intercompany Parent Subsidiaries Subsidiaries Eliminations Consolidated ----------- ------------ ------------- ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $(21,438) $ 33,530 $ 2,167 $ - $ 14,259 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion, and amortization 5,887 16,741 1,150 - 23,778 Deferred income tax 5,328 1,450 1,197 - 7,975 Other noncash items - 221 - - 221 Change in assets and liabilities resulting from operating activities: Accounts receivable and other 3,305 (3,242) (9,453) - (9,390) Inventory (3) (1,786) (16,450) - (18,239) Accounts payable and other current liabilities (4,116) 6,051 9,343 425 11,703 --------- ---------- ----------- ----------- ----------- NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES (11,037) 52,965 (12,046) 425 30,307 ----------- ------------ ----------- ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Payments for acquisition, exploration, and development costs (6,772) (98,874) - - (105,646) Payments for crude oil pipeline, gathering terminal assets - - (923) - (923) Proceeds from the sale of oil and natural gas properties 2,667 - - - 2,667 Payments for additions to other property and other assets (430) (3,184) (118) - (3,732) ----------- ------------ ------------- ----------- ----------- NET CASH USED IN INVESTING ACTIVITIES (4,535) (102,058) (1,041) - (107,634) ----------- ------------ ------------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Advances/investments with affiliates (45,228) 49,638 (4,410) - - Proceeds from long-term debt 266,905 - - - 266,905 Proceeds from short-term debt - - 39,000 - 39,000 Proceeds from sale of capital stock, options and warrants 1,104 - - - 1,104 Principal payments of long-term debt (206,500) (511) - - (207,011) Principal payments of short-term debt - - (21,000) - (21,000) Other (474) - - - (474) ----------- ------------ ------------- ----------- ----------- NET CASH PROVIDED BY FINANCING ACTIVITIES 15,807 49,127 13,590 - 78,524 ----------- ------------ ------------- ----------- ----------- Net increase in cash and cash equivalents 235 34 503 425 1,197 Cash and cash equivalents, beginning of period 4,676 229 949 (3,337) 2,517 ----------- ------------ ------------- ----------- ----------- Cash and cash equivalents, end of period $ 4,911 $ 263 $ 1,452 $ (2,912) $ 3,714 =========== ============ ============= =========== ===========
F-43 EX-23.1 2 0002.txt CONSENT OF PRICEWATERHOUSECOOPERS LLP EXHIBIT 23.1 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-80364, 333-01851, 33-84064, 333-42773, 333- 42767, 333-65939) and Form S-8 (Nos. 33-43788, 33-48610, 33-53802, 33-06191, 333-27907, 333-45558, 333-45562) of Plains Resources Inc. of our report dated March 29, 2000, relating to the consolidated financial statements which appear in this Annual Report on Form 10-K. PricewaterhouseCoopers LLP Houston, Texas January 18, 2001 EX-27 3 0003.txt FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1999 AND CONSOLIDATED STATEMENT OF INCOME FOR THE YEAR ENDED DECEMBER 31, 1999, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 68,228 0 521,948 0 78,349 772,140 1,190,167 402,514 1,689,560 656,273 0 138,813 23,300 1,792 15,527 1,689,560 4,742,690 4,770,171 4,740,862 4,809,262 0 0 46,378 (45,266) (20,479) (24,787) 0 (544) 0 (25,331) (2.05) (2.05)
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