-----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, Mu89H2aGJKQW4Ro9QM2hkO17TvLEXJAqULxM7AEo+akrRyNWWo+YqV2FGGJs7EbM QWMUd8fkoYpQ/CFl3IU85A== 0000899243-99-000613.txt : 19991018 0000899243-99-000613.hdr.sgml : 19991018 ACCESSION NUMBER: 0000899243-99-000613 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PLAINS RESOURCES INC CENTRAL INDEX KEY: 0000350426 STANDARD INDUSTRIAL CLASSIFICATION: 5172 IRS NUMBER: 132898764 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 033-50572 FILM NUMBER: 99580127 BUSINESS ADDRESS: STREET 1: 500 DALLAS STREET 2: SUITE 700 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7136541414 MAIL ADDRESS: STREET 1: 1600 SMITH STREET STREET 2: SUITE 1500 CITY: HOUSTON STATE: TX ZIP: 77002 10-K 1 FORM 10-K - - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ___________________________ FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to _____________ Commission file number: 0-9808 PLAINS RESOURCES INC. (Exact name of registrant as specified in its charter) Delaware 13-2898764 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 500 Dallas Houston, Texas 77002 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (713) 654-1414 Securities registered pursuant to Section 12(b) of the Act: Title of each class: Name of each exchange on which registered: -------------------- ---------------------------------------- Common Stock, par value $.10 American Stock Exchange per share Securities registered pursuant to Section 12(g) of the Act: None 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 the filing requirements for the past 90 days. Yes x No --- --- 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 $234,602,780 on March 26, 1999 (based on $14.25 per share, the last sale price of the Common Stock as reported on the American Stock Exchange Composite Tape on such date). 16,891,617 shares of the registrant's Common Stock were outstanding as of March 26, 1999. DOCUMENTS INCORPORATED BY REFERENCE. The information required in Part III of this 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. [X] - - -------------------------------------------------------------------------------- PLAINS RESOURCES INC. AND SUBSIDIARIES 1998 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 Units and Related Unitholder Matters 34 Item 6. Selected Financial Data 35 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 36 Item 7A. Qualitative and Quantitative Disclosures About Market Risk 46 Item 8. Financial Statements and Supplementary Data 47 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 47 PART III Item 10. Directors and Executive Officers 47 Item 11. Executive Compensation 48 Item 12. Security Ownership of Certain Beneficial Owners and Management 48 Item 13. Certain Relationships and Related Transactions 48 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 48
FORWARD-LOOKING STATEMENTS This Annual Report on Form 10-K contains forward-looking statements and information that are based on the beliefs of Plains Resources Inc. and subsidiaries, as well as assumptions made by, and information currently available to, the Company. 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 the Company's business strategy, plans and objectives of management of the Company for future operations. Such statements reflect the current views of the Company with respect to future events, based on what they believe are reasonable assumptions. These statements, however, are subject to certain risks, uncertainties and assumptions, including, but not limited to (i) uncertainties inherent in the exploration for and development and production of oil and gas and in estimating reserves, (ii) unexpected future capital expenditures (including the amount and nature thereof), (iii) impact of crude oil price fluctuations, (iv) the effects of competition, (v) the success of the Company's risk management activities, (vi) the availability (or lack thereof) of acquisition or combination opportunities, (vii) the availability of adequate supplies of and demand for crude oil in areas of midstream operations, (viii) the impact of current and future laws and governmental regulations, (ix) environmental liabilities that are not covered by an indemnity or insurance and (x) general economic, market or business conditions and (xi) inherent uncertainties associated with the Year 2000 issues. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those in the forward-looking statements. Except as required by applicable securities laws, the Company does not intend to update these forward-looking statements and information. CERTAIN DEFINITIONS 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 "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 the Company's 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 reduced by estimated future operating expenses, development expenditures and abandonment costs (net of salvage value) associated therewith (before income taxes), calculated using product prices in effect on the date of determination, and "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 ITEM 1. BUSINESS Plains Resources Inc. is an independent energy company engaged in the acquisition, exploitation, development, exploration and production of crude oil and natural gas. Through its majority ownership in Plains All American Pipeline, L.P. ("PAA"), the Company is engaged in the midstream activities of marketing, transportation, terminalling and storage of crude oil. The Company's upstream oil and natural gas activities are focused in California in the Los Angeles Basin (the "LA Basin"), the Arroyo Grande Field and the Mt. Poso Field (collectively the "California Properties"), the Sunniland Trend of South Florida (the "Sunniland Trend") and the Illinois Basin in southern Illinois (the "Illinois Basin"). The Company's midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. The Company's upstream operations contributed approximately 58% of the Company's earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") for the fiscal year ending December 31, 1998, while the Company's midstream activities accounted for 42%. The Company conducts its upstream operations in each of its three core areas through wholly owned subsidiaries. The California Properties are operated by Stocker Resources, Inc. ("Stocker"), the Sunniland Trend properties are operated by Calumet Florida, Inc. ("Calumet") and the Illinois Basin Properties are operated by Plains Illinois Inc. ("Plains Illinois"). A wholly-owned subsidiary of the Company, Plains All American Inc. ("PAAI" or the "General Partner"), is both the general partner and majority owner of PAA. As a result of its general partner interest and ownership of approximately 17 million common and subordinated units, PAAI holds a 57% interest in PAA. For financial statement purposes, the assets, liabilities and earnings of PAA are included in the Company's consolidated financial statements, with the public unitholders' interest reflected as a minority interest. References to the Company in this Annual Report on Form 10-K (the "Report") include Plains Resources Inc. and its subsidiaries, including PAA, except as the context may otherwise require. The following chart sets forth the organization relationship of the Company's upstream and midstream subsidiaries: [GRAPH APPEARS HERE] Upstream Activities The Company's upstream business strategy is to increase its proved reserves and cash flow by exploiting and producing crude oil and associated natural gas from its existing properties, acquiring additional underdeveloped crude oil properties and exploring for significant new sources of reserves. The Company concentrates its acquisition and exploitation efforts on mature but underdeveloped crude oil producing properties that meet the Company's targeted criteria. Generally, such properties were previously owned by major integrated or large independent oil and natural gas companies, have produced significant volumes 3 since initial discovery and have significant estimated remaining reserves in place. Management believes that it has developed a proven record in acquiring and exploiting underdeveloped crude oil properties where it believes substantial reserve additions and cash flow increases can be made through improved production practices and recovery techniques and relatively low risk development drilling. An integral component of the Company's exploitation effort is to increase unit operating margins, and therefore cash flow, by reducing unit production expenses and increasing wellhead price realizations. The Company seeks to complement these exploitation efforts by pursuing certain higher risk exploration opportunities that offer potentially higher rewards. As part of its business strategy, the Company periodically evaluates, and from time to time has elected to sell, certain of its mature producing properties that it considers to be nonstrategic or fully valued. Such sales enable the Company to focus on its core properties, maintain financial flexibility, control overhead and redeploy the sales proceeds to activities that have potentially higher financial returns. The Company's marketing of its own crude oil production takes advantage of the marketing expertise developed through its midstream activities. See "--Midstream Activities". During the five-year period ended December 31, 1998, the Company incurred aggregate acquisition, exploitation, development, and exploration costs of approximately $404.4 million, resulting in proved oil and natural gas reserve additions (including revisions of estimates but excluding production) of approximately 124.4 million BOE, or $3.25 per BOE, through implementation of its business strategy. See "Item 2, Properties -- Oil and Natural Gas Reserves". Approximately 97% of these expenditures were directed toward the acquisition, exploitation and development of proved reserves while approximately 3% were incurred on exploration activities. To manage its exposure to commodity price risk, the Company's upstream business routinely hedges a portion of its crude oil production. For 1999, the Company has entered into various fixed price arrangements that generally provide the Company with downside price protection on approximately 9,000 barrels of oil per day at a NYMEX crude oil spot price ("NYMEX Crude Oil Price") of approximately $18.25 per barrel. Thus, based on the Company's average fourth quarter 1998 crude oil production rate, these arrangements generally provide the Company with downside price protection for approximately 45% of its crude oil production. In addition, the Company also has fixed price arrangements on 2,000 barrels per day in 2000 at a NYMEX Crude Oil Price of $15.30 per barrel, or approximately 10% of fourth quarter 1998 crude oil production levels. The following table sets forth certain information with respect to the Company's reserves over the last five years. Such reserve volumes and values were determined under the method prescribed by the Securities and Exchange Commission (the "SEC"), which requires the application of year-end oil and natural gas prices for each year, held constant throughout the projected reserve life. The benchmark NYMEX oil price of $12.05 per barrel used in preparing year- end 1998 reserve estimates represented the lowest year-end oil price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. See "Item 2, Properties -- Oil and Natural Gas Reserves" and "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations".
AS OF OR FOR THE YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------- 1998 1997 1996 1995 1994 --------- -------- -------- ------- ---------- (IN THOUSANDS, EXCEPT RATIOS AND PER UNIT AMOUNTS) Present Value of Proved Reserves $226,943 (1) $510,993 $764,774 $366,780 $ 229,371 Proved Reserves Crude oil and natural gas liquids (Bbls) 120,208 151,627 115,996 94,408 61,459 Natural gas (Mcf) 86,781 60,350 37,273 43,110 51,009 Oil equivalent (BOE) 134,672 (1) 161,685 122,208 101,593 69,960 Reserve Replacement Ratio (2) NM (3) 603% (4) 454% 647% (5) 619% Reserve Replacement Cost per BOE(6) NM (3) $ 2.71 $ 1.76 $ 2.14 $ 1.49 Total upstream capital costs incurred $100,935 $127,378 $ 51,255 $ 84,012 $ 40,849 Percentage of total upstream capital costs attributable to: Acquisition 10% 34% 7% 71% 48% Development 88% 65% 88% 27% 38% Exploration 2% 1% 5% 2% 14% Year-end NYMEX Crude Oil Price $12.05 $ 18.34 $ 25.92 $ 19.55 $ 17.76
(footnotes on following page) 4 _______________________ (1) A large portion of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. By comparison, calculating these amounts using a price of $18.34 per barrel, which was the NYMEX Crude Oil Price at December 31, 1997, results in a Present Value of Proved Reserves of $705 million and estimated net proved reserves of 219 million BOE. Such information is based upon reserve reports prepared by independent petroleum engineers, in accordance with the rules and regulations of the SEC, except that it uses the same crude oil price used in preparing year-end 1997 reserve information. See "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices". (2) 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 ("Reserve Additions"), by (b) each respective years' production. (3) NM -- Due to negative volume revision related solely to price, such information is not meaningful. Based upon a NYMEX Crude Oil Price of $18.34 per barrel, the 1998 Reserve Replacement Ratio and Reserve Replacement Cost per BOE were 819% and $1.53, respectively. (4) 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. (5) 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. (6) 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 The Company is continually engaged in the exploitation and development of its existing property base and the evaluation and pursuit of additional underdeveloped properties for acquisition. The Company focuses on mature but underdeveloped producing crude oil properties in areas where the Company believes 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, the Company seeks to increase production rates and improve a property's operating margin by reducing unit production costs and enhancing the marketing arrangements of the oil production. Once the Company identifies a prospective property for acquisition, it conducts a technical review of existing production and operating practices to identify any previously unrecognized 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 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 the Company's offer to purchase. The Company typically seeks to acquire a majority interest in the properties it has identified and to act as operator of those properties. The Company has 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 the Company successfully purchases such properties, it then implements its 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, the Company may also seek to increase its interest in the properties through acquisitions of offsetting acreage, farmout drilling arrangements and the purchase of minority interests in the properties. By implementing its exploitation plan, the Company seeks to increase volumes and expand its reserve base. The results of such activities are reflected in additions and revisions to proved reserves. During the five-year period ending December 31, 1998, net additions and revisions to proved reserves totaled 50.3 million BOE or approximately 162% of cumulative net production for such period. Such reserves were added at an aggregate average cost of $5.33 per BOE. Such unit cost reflects the 5 negative impact of a downward volume revision in 1998 related solely to lower oil prices at December 31, 1998. This activity excludes reserves added as a result of the Company's acquisition activities. Reserve additions related solely to the Company's acquisition activities totaled 74.1 million BOE and were added at an aggregate average cost of $1.84 per BOE. The Company's properties in its three core areas represent 100% of total proved reserves at December 31, 1998. Such properties were previously owned and operated by major integrated oil and natural gas companies and are comprised of underdeveloped crude oil properties believed by the Company to have significant upside potential that can be evaluated through development and exploitation activities. During 1999, the Company estimates it will spend approximately $64 million on the development and exploitation of its California, Sunniland Trend and Illinois Basin Properties. Set forth below is a discussion of such properties. Current Exploitation Projects California Properties. Before the Company acquired it in May 1992, Stocker was a sole purpose company formed in 1990 to acquire substantially all of Chevron USA's ("Chevron") producing oil properties in the LA Basin. Following the initial acquisition, the Company expanded its 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. All of the Company's properties in the LA Basin acquired prior to 1997 are collectively referred to herein as the "LA Basin Properties". The LA Basin Properties consist of long-life reserves discovered at various times between 1924 and 1966, and through December 31, 1998, the LA Basin Properties have produced over 426 MMBbls of oil and 364 Bcf of natural gas. The Company has 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, average daily production from this area, net to the Company's interest, has increased from approximately 6,700 BOE per day in 1992 to an average of 11,100 BOE per day during the fourth quarter of 1998. The Company has expended approximately $156.5 million in direct acquisition, development and exploitation capital on the LA Basin Properties. From the effective dates of acquisition through December 31, 1998, net production from such properties totaled 22.2 million BOE, generating cumulative net margin (oil and natural gas revenue less production expenses) and proceeds from minor property sales of approximately $170.6 million. Total estimated proved reserves attributable to the LA Basin Properties have increased from 17.7 million BOE at initial acquisition to approximately 63 million BOE at December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, total estimated proved reserves were 81.1 million BOE at December 31, 1998. As a result, The Company's aggregate reserve addition cost to date for the LA Basin Properties is approximately $1.83 per BOE based on a NYMEX Crude Oil Price of $12.05 per barrel, and $1.51 per BOE based on $18.34 per barrel. During 1998, the unit gross margin for this area averaged $7.14 per BOE. Estimated future net revenues and the Present Value of Proved Reserves at December 31, 1998, were estimated at $326.5 million and $161.1 million, respectively, based on a NYMEX Crude Oil price of $12.05 per barrel, and $733.6 million and $354.6 million, respectively, based on $18.34 per barrel. The Company estimates it will spend approximately $27 million during 1999 on the further development and exploitation of the LA Basin Properties. The Company expanded its operations in the LA Basin with the acquisition of the Montebello Field (the "Montebello Acquisition"), and expanded into other California areas with the acquisition of the Arroyo Grande Field (the "Arroyo Grande Acquisition") and the Mt. Poso Field (the "Mt. Poso Acquisition"). Combined, these three fields added approximately 51 million BOE to the Company's proved reserves at the acquisition dates. In March 1997, the Company completed the acquisition of Chevron's interest in the Montebello Field for approximately $25 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 includes approximately 450 acres of surface fee land. The Montebello Field, which is located approximately 15 miles from the Company's existing LA Basin operations, has produced approximately 108 MMBbls of oil and 100 Bcf of natural gas since its discovery in 1917 and added approximately 23 MMBbls of oil equivalent to the Company's proved reserves at the acquisition date. Average daily production from this field, net to the Company's interest, has increased from approximately 930 BOE at the acquisition date to an average of approximately 1,520 BOE per day during the fourth quarter of 1998. Estimated total proved reserves and the Present Value of Proved Reserves at December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel were 8.3 MMBbls and $11 million, respectively. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, proved reserves and the Present Value of Proved Reserves were 23.3 MMBbls and $58 million, respectively, at 6 December 31, 1998. The Company estimates that it will spend approximately $11 million during 1999 on the development and exploitation of the Montebello Field. In November 1997, the Company 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 oil in place. The assets acquired include surface and development rights to approximately 1,000 acres included in the 1,500 acre unit. The field is under continuous steam injection and as of the acquisition date was producing approximately 1,600 barrels (approximately 1,500 barrels net to the Company's interest) of approximately 14 (degrees) API gravity oil per day from 70 wells and added approximately 20 MMBbls to the Company's proved reserves. The aggregate consideration for the Arroyo Grande Acquisition consisted of (i) rights to a non-producing property interest conveyed to Shell, (ii) the issuance of 46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D Preferred Stock") with an aggregate stated value of $23.3 million, and (iii) a five-year warrant to purchase 150,000 shares of the Company's common stock ("Common Stock") at $25 per share. No proved reserves had been assigned to the rights to the property interest conveyed. Due to low crude oil prices throughout 1998, the Company delayed certain of its exploitation activities on the Arroyo Grande Field and focused on reducing operating expenses. Unit production expenses for the Arroyo Grande Field, which averaged $9.36 per BOE at the acquisition date, averaged $5.82 per BOE during the fourth quarter of 1998. Estimated total proved reserves and the Present Value of Proved Reserves at December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel were 34 MMBbls and $3 million, respectively. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, proved reserves and the Present Value of Proved Reserves were 63 MMBbls and $118 million, respectively, at December 31, 1998. The Company estimates that it will spend approximately $5 million during 1999 on the development and exploitation of the Arroyo Grande Field. During 1998, the Company 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. Since its discovery in 1926, the Mt. Poso Field has produced approximately 200 MMBbls of oil. At acquisition, the field was producing 1,200 barrels of oil per day of 15-17 degree API gravity crude. Estimated total proved reserves and the Present Value of Proved Reserves at December 31, 1998, based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel were 8 MMBbls and $14 million, respectively. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, proved reserves and the Present Value of Proved Reserves were 8 MMBbls and $46 million, respectively, at December 31, 1998. The Company estimates that it will spend approximately $8 million during 1999 on the development and exploitation of the Mt. Poso Field. As with its other California properties, the Company intends to aggressively exploit the properties it acquired in 1997 and 1998 to evaluate additional reserve potential identified during its acquisition analyses. In addition, the Company's exploitation plans for these properties target improving the unit gross margin by decreasing unit production expenses and increasing production volumes through production enhancement activities similar to those employed in its other California properties. Sunniland Trend Properties. During the first quarter of 1993, the Company acquired all of the capital stock of Calumet for approximately $5 million. Calumet was organized in February 1993 to purchase and operate a 50% working interest in six producing fields in South Florida located in the Sunniland Trend and previously owned and operated by Exxon Corporation ("Exxon"). During 1994, Calumet acquired the remaining 50% working interest in the Sunniland Trend Properties, increasing its working interest to approximately 100% and adding approximately five million barrels of oil to its proved reserve base at the acquisition date. The Company's aggregate interest in such properties is referred to as the "Sunniland Trend Properties". The aggregate purchase price for the additional 50% interest was approximately $13.6 million, including the issuance of a five-year warrant valued at $2 million to purchase 750,000 shares of Common Stock at an exercise price of $6.00 per share. The Sunniland Trend was discovered by Exxon in 1943, and the properties have produced approximately 94 MMBbls of oil through December 31, 1998. At the time of acquisition, production from the properties was about 900 barrels of oil per day net to the Company. As a result of development drilling on the property, the implementation of exploitation activities designed primarily to repair failed wells and to increase the fluid lift capacity of certain wells and the acquisition of the remaining 50% working interest, the Company's net production increased to an average of 4,200 barrels of oil per day during the fourth quarter of 1998. The Company has expended approximately $75.6 million in direct acquisition, development and exploitation capital on the Sunniland Trend Properties. From the effective dates of acquisition through December 31, 1998, net production from such properties totaled 8.1 MMBbls, generating cumulative net margin of approximately $55.8 million. Total estimated proved reserves attributable to the Sunniland Trend Properties have increased from approximately 5.0 MMBbls at initial acquisition to approximately 9.3 MMBbls based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, total estimated proved reserves were 7 20.4 MMBbls at December 31, 1998. As a result, the Company's aggregate reserve addition cost to date for the Sunniland Trend Properties is approximately $4.36 per BOE based on a NYMEX Crude Oil Price of $12.05 per barrel, and $2.65 per BOE based on $18.34 per barrel. During 1998, the unit gross margin for this area averaged $5.22 per BOE. At December 31, 1998, the Present Value of Proved Reserves was estimated at $1.6 million and $60.3 million, respectively, based on a NYMEX Crude Oil Price of $12.05 per barrel and $18.34 per barrel, respectively. During 1999, the Company estimates it will spend approximately $8 million on the further development and exploitation of the Sunniland Trend Properties. In addition, the Company intends to conduct exploration activities in this trend during 1999. See "-- Exploration-- Current Exploration Projects -- Sunniland Trend". Illinois Basin Properties. In December 1995, the Company acquired all of Marathon Oil Company's ("Marathon") producing and nonproducing upstream oil and natural gas assets in the Illinois Basin (the "Illinois Basin Properties"). This acquisition was effective as of November 1, 1995. At the acquisition date, the Company added approximately 17.3 MMBbls of oil to its proved reserve base. The aggregate purchase price, including associated closing costs, was $51.5 million, comprised of 798,143 shares of Common Stock valued at $6.5 million and $45.0 million cash. The majority of the cash portion was funded with the proceeds of a $42 million bank facility. The Illinois Basin Properties consist of long-life oil reserves. The largest field included in the Illinois Basin Properties was discovered in 1905 and has produced over 411 MMBbls of oil through December 31, 1998. The Company has expended approximately $76.1 million in direct acquisition, development and exploitation capital on the Illinois Basin Properties. From the effective date of acquisition through December 31, 1998, net production from such properties totaled 4.1 MMBbls, generating cumulative net margin of approximately $40.7 million. The Company's 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 $8.60 per BOE during 1998. Total estimated proved reserves attributable to the Illinois Basin Properties were 17.3 MMBbls at initial acquisition as compared to approximately 12.0 MMBbls based on the year-end 1998 NYMEX Crude Oil Price of $12.05 per barrel. Based on $18.34 per barrel, the NYMEX Crude Oil Price used in preparing year-end 1997 reserve information, total estimated proved reserves were 22 MMBbls at December 31, 1998. As a result, the Company's aggregate reserve addition cost to date for the Illinois Basin Properties is approximately $4.73 per BOE based on a NYMEX Crude Oil Price of $12.05 per barrel, and $2.87 per BOE based on $18.34 per barrel. Estimated future net revenues and the Present Value of Proved Reserves at December 31, 1998, were estimated at $27.9 million and $16.9 million, respectively, based on a NYMEX Crude Oil Price of $12.05 per barrel, and $143.0 million and $66.5 million, respectively, based on $18.34 per barrel. During 1999, the Company estimates it will spend approximately $5 million implementing its exploitation plan on the Illinois Basin Properties. The primary focus of such development and exploitation program during 1999 will be directed towards aggressively implementing projects to evaluate alternative waterflood realignment patterns and injection methods. General. The Company believes that its properties in its three core areas hold potential for additional increases in production, reserves and cash flow. However, the ability of the Company to achieve such increases could be adversely affected by future decreases in the demand for oil and natural gas, impediments in marketing production, operating risks, unavailability of capital, adverse changes in governmental regulations or other currently unforeseen developments. Accordingly, there can be no assurance that such increases will be achieved. The Company believes that attractive acquisition opportunities which fit the Company's criteria will continue to be made available by both major and independent oil companies. In addition to more typical acquisitions, the Company also intends to pursue joint ventures and strategic alliances that provide the Company the opportunity to use its exploitation and operating skillsets and its capital without acquiring the entire property interest. While the Company is continually evaluating such opportunities, there can be no assurance that any of these efforts will be successful. The Company's 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 the Company has historically acquired producing properties located only in the continental United States, it from time to time evaluates, and may in the future seek to acquire, properties located outside the continental United States. 8 Exploration Exploration Strategy The Company seeks to complement its strategy of acquiring and exploiting mature but underdeveloped crude oil properties by dedicating a substantially smaller portion of its annual capital expenditures to higher risk but potentially higher reward exploration opportunities. The Company focuses on exploration opportunities that, if successful, could have a substantial positive impact on production, cash flow and ultimately proved reserves. However, there can be no assurance that any of its exploration projects will be successful. Current Exploration Projects Sunniland Trend. The focus of the Company's exploration effort in the Sunniland Trend is to identify and evaluate prospects that are analogous to the existing producing fields in this trend. Although this trend was discovered in 1943, the Company is attempting to integrate historical exploration methods with recent advancements in seismic technology to evaluate the exploration potential of the Sunniland Trend. In February 1998, the Company and Collier Resources Company ("Collier") executed an exploration agreement (the "Exploration Agreement") covering approximately 800,000 mineral acres which are located onshore South Florida in Collier, Lee and Hendry Counties. Approximately 50% of such acreage is located under federally owned surface land. Terms of the Exploration Agreement provide for a minimum term of two years with extensions at the Company's option for up to eight years. Subject to certain elections, work commitments of the Exploration Agreement provide for the Company to spend up to $20 million on exploration activities involving Collier's mineral holdings over the next several years. During the first half of 1999, the Company intends to acquire a 14-square mile 3D seismic survey over portions of its largest producing field in the Sunniland Trend and prospective areas adjacent thereto. Also during 1999, the Company will be required to make certain elections and associated capital commitments to maintain its control over the entire acreage position covered by the Exploration Agreement. The Company cannot at this time predict whether or not it will elect to maintain control over all or a portion of this acreage. Such elections will be influenced by the results of the 3D seismic survey. General. During 1999, the Company estimates it will spend approximately $3 million on exploration activities, principally in the Sunniland Trend. While all drilling activities are subject to numerous risks, the risks associated with exploration activities are significantly greater than those associated with the Company's other exploitation and development activities. There can be no assurance that any of the Company's current exploration or higher risk exploitation projects will result in the discovery of proved reserves or the establishment of commercially viable oil or natural gas production. The Company has historically conducted a portion of its exploration activities with outside partners. When deemed appropriate, the Company will continue to solicit industry and financial partners to participate in exploration projects on negotiated terms. The level of the Company's capital expenditures for these projects, and its working and revenue interests, will vary depending on the amount and terms of such outside participation. Disposition of Properties The Company periodically evaluates, and from time to time has elected to sell, certain of its mature producing properties that it considers to be nonstrategic or fully valued. Such sales enable the Company to focus on its core properties, maintain financial flexibility, reduce overhead and redeploy the proceeds therefrom to activities that the Company believes have a higher potential financial return. During 1997 and 1996, the Company sold nonstrategic oil and natural gas properties located primarily in Louisiana and Utah for proceeds of $2.7 million and $3.1 million, respectively. As a result, 100% of the Company's 1998 year-end proved reserve volumes and proved reserve value were associated with its properties in California, the Sunniland Trend and the Illinois Basin. Midstream Activities The Company's midstream activities are conducted through PAA. PAA was formed in 1998 to acquire and operate the business and assets of the Company's wholly owned midstream subsidiaries (the "Plains Midstream Subsidiaries"). PAAI, a wholly owned subsidiary of the Company, is the general partner of PAA. PAA is engaged in interstate and intrastate crude oil pipeline transportation and crude oil terminalling and storage activities and gathering and marketing activities. PAA's operations are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. 9 Formation of PAA, Initial Public Offering and Concurrent Transactions On November 23, 1998, PAA completed an initial public offering (the "IPO") of 13,085,000 common units representing limited partner interests (the "Common Units") in PAA and received therefrom net proceeds of approximately $244.7 million. Concurrently with the closing of the IPO, certain transactions described in the following paragraphs were consummated in connection with the formation of PAA. Such transactions and the transactions which occurred in conjunction with the IPO are referred to in this Report as the "Transactions". For presentation efficiency, certain capitalized terms are defined under "-- Midstream Activities -- General". Certain of the Plains Midstream Subsidiaries were merged into the Company, which sold the assets of these subsidiaries to PAA in exchange for $64.1 million and the assumption of $11.0 million of related of indebtedness. At the same time, the General Partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System, which it acquired in July 1998 for approximately $400 million (the "All American Pipeline Acquisition"), to PAA in exchange for (i) 6,974,239 Common Units, 10,029,619 Subordinated Units and an aggregate 2% general partner interest in PAA, (ii) the right to receive Incentive Distributions; and (iii) the assumption by PAA of $175 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 the Company, PAA distributed approximately $177.6 million to the General Partner and used approximately $3 million of the remaining proceeds to pay expenses incurred in connection with the Transactions. 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 establish new credit facilities for PAA. The balance, $56.6 million, was distributed to the Company, which used the cash to repay indebtedness and for other general corporate purposes. In addition, concurrently with the closing of the IPO, PAA entered into a $225 million bank credit agreement (the "Bank Credit Agreement") that includes a $175 million term loan facility (the "Term Loan Facility") and a $50 million revolving credit facility (the "PAA Revolving Credit Facility"). PAA may borrow up to $50 million under the PAA Revolving Credit Facility for acquisitions, capital improvements, working capital and general business purposes. At closing, PAA had $175 million outstanding under the Term Loan Facility, representing indebtedness assumed from the General Partner. In conjunction with the IPO, the Company entered into various agreements with PAA, including (i) the Omnibus Agreement, providing for the resolution of certain conflicts arising from the conduct of PAA and the Company of related businesses and for the General Partner's indemnification of PAA for certain matters and (ii) the Crude Oil Marketing Agreement (the "Crude Oil Marketing Agreement") which provides for the marketing by PAA of the Company's crude oil production. Business Activities PAA owns and operates a 1,233-mile seasonally heated, 30-inch, common carrier crude oil pipeline extending from California to West Texas (the "All American Pipeline") and a 45-mile, 16-inch, crude oil gathering system in the San Joaquin Valley of California (the "SJV Gathering System"), both of which the General Partner purchased from The Goodyear Tire and Rubber Company ("Goodyear") in July 1998 for approximately $400 million. PAA also owns and operates a two million barrel, above-ground crude oil terminalling and storage facility in Cushing, Oklahoma, (the "Cushing Terminal") that has an estimated daily throughput capacity of approximately 800,000 barrels per day. The All American Pipeline is one of the newest interstate crude oil pipelines in the United States, having been constructed by Goodyear between 1985 and 1987 at a cost of approximately $1.6 billion, and is the largest capacity crude oil pipeline connecting California and Texas, with a design capacity of 300,000 barrels per day of heavy crude oil. In West Texas, the All American Pipeline interconnects with other crude oil pipelines that serve the Gulf Coast and Cushing, Oklahoma, the largest crude oil trading hub in the United States and the designated delivery point for NYMEX crude oil futures contracts (the "Cushing Interchange"). Production currently transported on the All American Pipeline originates from the Santa Ynez field operated by Exxon and the Point Arguello field operated by Chevron, both offshore California, and from the San Joaquin Valley. Exxon and Chevron, as well as Texaco and Sun Operating L.P., which are other working interest owners, are contractually obligated to ship all of their production from these offshore fields on the All American Pipeline through August 2007. The SJV Gathering System is used primarily to transport crude oil from fields in the San Joaquin Valley to the All American Pipeline and to intrastate pipelines owned by third parties. The capacity of the SJV Gathering System is approximately 140,000 barrels per day. In addition to transporting third-party volumes for a tariff, PAA is engaged in merchant activities designed to capture price 10 differentials between the cost to purchase and transport crude oil to a sales point and the price received for such crude oil at the sales point. The Cushing Terminal was completed in 1993, making it the most modern facility in the area, and includes state-of-the-art design features. PAA has initiated an expansion project that will add one million barrels of storage capacity at an aggregate cost of approximately $10 million. The expansion project is expected to be completed by the second quarter of 1999. Upon completion of the expansion project, management believes the Cushing Terminal will be the third largest facility at the Cushing Interchange (and the largest not owned by a major oil company) with an estimated 12% of that area's storage capacity. PAA also owns 586,000 barrels of tank capacity along the SJV Gathering System, 955,000 barrels of tank capacity along the All American Pipeline and 360,000 barrels of tank capacity at Ingleside, Texas, on the Gulf Coast (the "Ingleside Terminal"). PAA's terminalling and storage operations generate revenue from the Cushing Terminal through a combination of storage and throughput fees from (i) refiners and gatherers seeking to segregate or custom blend crude oil for refining feedstocks, (ii) pipelines, refiners and traders requiring segregated tankage for foreign crude oil, (iii) traders who make or take delivery under NYMEX contracts and (iv) producers seeking to increase their marketing alternatives. The Cushing Terminal and PAA's other storage facilities also facilitate PAA's merchant activities by enabling PAA to buy and store crude oil when the price of crude oil in a given month is less than the price of crude oil in a subsequent month (a "contango" market) and to simultaneously sell crude oil futures contracts for delivery of the crude oil in such subsequent month at the higher futures price, thereby locking in a profit. PAA's gathering and marketing operations include the purchase of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities, the transportation of crude oil on trucks, barges or pipelines, and the subsequent resale or exchange of crude oil at various points along the crude oil distribution chain. The crude oil distribution chain extends from the wellhead where crude oil moves by truck and gathering systems to terminal and pipeline injection stations and major pipelines and is transported to major crude oil trading locations for ultimate consumption by refineries. In many cases, PAA matches supply and demand needs by performing a merchant function-- generating gathering and marketing margins by buying crude oil at competitive prices, efficiently transporting or exchanging the crude oil along the distribution chain and marketing the crude oil to refineries or other customers. When there is a higher demand than supply of crude oil in the near term, the price of crude oil in a given month exceeds the price of crude oil in a subsequent month (a "backward" market). A backward market has a positive impact on marketing margins because crude oil gatherers can capture a premium for prompt deliveries. Likewise, since a premium is paid for prompt deliveries, storage opportunities are generally not profitable. For the year ended December 31, 1998, PAA's pro forma gross margin, EBITDA and net income totaled $74.1 million, $68.2 million and $43.9 million, respectively. On a pro forma basis, the All American Pipeline and the SJV Gathering System accounted for approximately 68% of PAA's gross margin for the year ended December 31, 1998, while the terminalling and storage activities and gathering and marketing activities accounted for approximately 32%. Pro forma information assumes the All American Pipeline Acquisition as well as the IPO occurred on January 1, 1998. Pending Acquisition On March 17, 1999, PAA signed a definitive agreement with Marathon Ashland Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets. The cash purchase price for the acquisition is approximately $138 million, plus associated closing and financing costs. The purchase price is subject to adjustment at closing for working capital on April 1, 1999, the effective date of the acquisition. Closing of the transaction is subject to regulatory review and approval, consents from third parties, and customary due diligence. Subject to satisfaction of the foregoing conditions, the transaction is expected to close in the second quarter of 1999. PAA has received a financing commitment from one of its existing lenders, which in addition to other financial resources currently available to PAA, will provide the funds necessary to complete the transaction. The definitive agreement provides that if either party fails to perform its obligations thereunder through no fault of the other party, such defaulting party shall pay the nondefaulting party $7.5 million as liquidated damages. Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum LLC, is engaged in crude oil transportation, trading and marketing, operating in 14 states with more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Howard, Martin, Midland, Regan, Upton and Irion Counties, Texas. The assets to be acquired also include approximately one million barrels of crude oil used for linefill requirements. 11 Crude Oil Pipeline Operations All American Pipeline The All American Pipeline is a common carrier crude oil pipeline system that transports crude oil produced from fields offshore and onshore California to locations in California and West Texas pursuant to tariff rates regulated by the Federal Energy Regulatory Commission ("FERC"). 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 PAA. The American Pipeline is comprised of a heated pipeline system which extends approximately 10 miles from Exxon's onshore facilities at Las Flores on the California coast to Chevron's onshore facilities at Gaviota, California (24- inch diameter pipe) and continues from Gaviota approximately 1,223 miles through Arizona and New Mexico to West Texas (30-inch diameter pipe) where it interconnects with other pipelines. These interconnecting common carrier pipelines transport crude oil to the refineries located along the Gulf Coast and to the Cushing Interchange. At the Cushing Interchange, these pipelines connect with other pipelines that deliver crude oil to Midwest refiners. The All American Pipeline also includes various pumping and heating stations, as well as approximately one million barrels of crude oil storage tank capacity, to facilitate the transportation of crude oil. The tank capacity is located at stations in Sisquoc, Pentland and Cadiz, California, and at the station in Wink, Texas. Unlike many common carrier pipelines, PAA owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's linefill requirements. The All American Pipeline has a designed throughput capacity of 300,000 barrels per day of heavy crude oil and larger volumes of lighter crude oils. As currently configured, the pipeline's daily throughput capacity is approximately 216,000 barrels of heavy oil. In order to achieve designed capacity, certain nominal capital expenditures would be required. The All American Pipeline is operated from a control room in Bakersfield, California with a supervisory control and data acquisitions ("SCADA") computer system designed to continuously monitor quantities of crude oil injected in and delivered through the All American Pipeline as well as pressure and temperature variations. This technology also allows for the batching of several different types of crude oil with varying gravities. The SCADA system is designed to enhance leak detection capabilities and provides for remote-controlled shut-down at every pump station on the All American Pipeline. Pumping stations are linked by telephone and microwave communication systems for remote-control operation of the All American Pipeline which allows most of the pump stations to operate without full time site personnel. PAA performs scheduled maintenance on the pipeline and makes repairs and replacements when necessary or appropriate. As one of the most recently constructed major crude oil pipeline systems in the United States, the All American Pipeline requires a relatively low level of maintenance capital expenditures. PAA attempts to control corrosion of the pipeline through the use of corrosion inhibiting chemicals injected into the crude stream, external pipe coatings and an anode bed based cathodic protection system. PAA monitors the structural integrity of the All American Pipeline through a program of periodic internal inspections using electronic "smart pig" instruments. PAA conducts a weekly aerial surveillance of the entire pipeline and right-of-way to monitor activities or encroachments on rights-of-way. Maintenance facilities containing equipment for pipe repair, digging and light equipment maintenance are strategically located along the pipeline. PAA believes that the All American Pipeline has been constructed and is 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 standards of industry practice. System Supply The All American Pipeline transports several different types of crude oil, including (i) Outer Continental Shelf ("OCS") 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, (ii) Elk Hills crude oil, received at Pentland, California from a connection with the SJV Gathering System and (iii) various crude oil blends received at Pentland from the SJV Gathering System, including West Coast Heavy and Mojave Blend. OCS Supply. Exxon, which owns all of the Santa Ynez production, and Chevron, Texaco and Sun Operating L.P., which own approximately one-half of the Point Arguello production, have entered into transportation agreements committing to transport all of their production from these fields on the All American Pipeline. These agreements, which expire in August 2007, provide for a minimum tariff with annual escalations. At December 31, 1998, the tariffs averaged $1.41 per barrel for deliveries to connecting pipelines in California and $2.96 per barrel for deliveries to connecting pipelines in West Texas. 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 PAA have no other means of transporting their production and, therefore, ship their volumes on the All American Pipeline 12 at the posted tariffs. During 1998, approximately $33.6 million, or 45%, of PAA's pro forma gross margin was attributable to volumes received from the Santa Ynez field and approximately $12.9 million, or 17%, was attributable to volumes received from 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, -------------------------------------------------------------- 1998 1997 1996 1995 1994 1993 1992 1991 ------ ------ ------ ------ ------ ------ ------ ------ (barrels in thousands) Average daily volumes received from: Point Arguello (at Gaviota) 26 30 41 60 73 63 47 29 Santa Ynez (at Las Flores) 68 85 95 92 34 -- -- -- ------ ------ ------ ------ ------ ------ ------ ------ Total 94 115 136 152 107 63 47 29 ====== ====== ====== ====== ====== ====== ====== ======
Absent operational or economic disruptions, PAA anticipates that production from Point Arguello will continue to decline at percentage rates which approximate historical decline rates, but that average production received from the Santa Ynez field for 1999 will generally approximate 60,000 to 65,000 barrels per day. In connection with a proposed transfer of its ownership in Point Arguello to a private independent oil company, Chevron provided notice to the other working interest owners of its resignation as operator of the Point Arguello field. PAA is unable to determine at this time if the proposed transfer will occur or the consequences any such transfer or the absence of any such transfer will have on Point Arguello production and the resulting pipeline transportation. According to information published by the Minerals Management Service ("MMS"), significant additional proved, undeveloped reserves have been identified offshore California which have the potential to be delivered on the All American Pipeline. Future volumes of crude deliveries on the All American Pipeline will depend on a number of factors that are beyond PAA's control, including (i) the economic feasibility of developing the reserves, (ii) the economic feasibility of connecting such reserves to the All American Pipeline and (iii) the ability of the owners of such reserves to obtain the necessary governmental approvals to develop such reserves. The owners of these reserves are currently participating in a study (California Offshore Oil and Gas Energy Resources, "COOGER") with various private organizations and regulatory agencies to determine the best sites to locate onshore facilities that will be required to handle and process potential production from these undeveloped fields as well as the best methods of controlling potential environmental dangers associated with offshore drilling and production. These owners have also agreed to suspend drilling on the undeveloped leases until the COOGER study is completed. The COOGER study is anticipated to be completed by June 30, 1999, at which time owners of these undeveloped reserves must submit their development plans to the MMS. There can be no assurance that the owners will develop such reserves, that the MMS will approve development plans or that future regulations or litigation will not prevent or retard their ultimate development and production. There also can be no assurance that, if such reserves were developed, a competing pipeline might not be built to transport the production. In addition, a June 12, 1998 Executive Order of the President of the United States extends until the year 2012 a statutory moratorium on new leasing of offshore California fields. Existing fields are authorized to continue production, but federal, state and local agencies may restrict permits and authorizations for their development, and may restrict new onshore facilities designed to serve offshore production of crude oil. San Luis Obispo and Santa Barbara counties have adopted zoning ordinances that prohibit development, construction, installation or expansion of any onshore support facility for offshore oil and gas activity in the area, unless approved by a majority of the votes cast by the voters of either county in an authorized election. Any such restrictions, should they be imposed, could adversely affect the future delivery of crude oil to the All American Pipeline. San Joaquin Valley Supply. In addition to OCS production, crude oil from fields in the San Joaquin Valley is delivered into the All American Pipeline at Pentland through connections with the SJV Gathering System and pipelines operated by EOTT, L.P. and ARCO. The San Joaquin Valley is one of the most prolific oil producing regions in the continental United States, producing approximately 591,000 barrels per day of crude oil during the first nine months of 1998 which accounted for approximately 65% 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. 13
Year Ended December 31, ------------------------------------------------------------------------------ 1998(1) 1997 1996 1995 1994 1993 1992 1991 1990 1989 ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ (barrels in thousands) Average daily volumes: San Joaquin Valley production 591 584 579 569 578 588 609 634 629 646 Total California production 780 781 772 764 784 803 835 875 879 907 (excluding OCS volumes)
__________________________ (1) Reflects information through September 1998. Drilling and exploitation activities have increased in the San Joaquin Valley over the last few years, primarily due to the change in ownership of several large fields and technological advances in horizontal drilling and steam assisted recovery methods that have improved the overall economics of field development and reductions in the operating costs of these fields. The near term outlook for any potential production increases has been adversely affected by the depressed price of oil and related reductions in capital spending plans announced by several California producers. Alaskan North Slope Supply. Historically, the All American Pipeline had also transported volumes of Alaskan North Slope crude oil. In 1996, the U.S. government repealed the export ban on crude oil produced from the Alaskan North Slope which had effectively prohibited the sale of Alaskan North Slope crude oil to sources outside the U.S. Prior to its repeal, this ban had the impact of increasing volumes of Alaskan crude oil delivered into the California market. Shipments of Alaskan North Slope crude oil on the All American Pipeline ceased in February 1997, shortly after the repeal of the export ban. In addition, ARCO has sold the only pipeline that could bring Alaskan North Slope crude oil to the All American Pipeline. This pipeline will be converted to natural gas service thereby eliminating the physical capability to ship Alaskan North Slope Crude Oil on the All American Pipeline. System Demand Deliveries from the All American Pipeline are made to refineries within California, along the Gulf Coast or in the Midwest through connecting pipelines of other companies. Demand for crude oil shipped on the All American Pipeline in each of these markets is affected by numerous factors, including refinery utilization and crude oil slate requirements, regional crude oil production, foreign imports, intra-U.S. transfers of crude oil and the price differential (net of transportation cost) between the California and Midwest markets. Deliveries are made to California refineries through connections with third-party pipelines at Sisquoc, Pentland and Mojave. The deliveries at Sisquoc and Pentland are OCS crude oil while the deliveries at Mojave are primarily Mojave Blend. Crude oil transported to West Texas is primarily West Coast Heavy and is delivered to third-party pipelines at Wink and McCamey, Texas. At Wink, West Coast Heavy crude is blended with Domestic Sweet Crude to increase the gravity (the blend is commonly referred to as West Coast Sour), permitting delivery into third party pipelines that can transport the crude to the Cushing Interchange. At McCamey, West Coast Heavy and OCS crude oil are delivered to a third-party pipeline that supplies refiners on the Gulf Coast. The following table sets forth All American Pipeline average deliveries per day within and outside California for each of the years in the five-year period ended December 31, 1998.
Year Ended December 31, -------------------------------------- 1998 1997 1996 1995 1994 ------ ------ ------ ------ ------ (barrels in thousands) Average daily volumes delivered to: California Sisquoc 24 21 17 11 21 Pentland 69 74 71 65 56 Mojave 22 32 6 - - ------ ------ ------ ------ ------ Total California 115 127 94 76 77 Texas 59 68 113 141 108 ------ ------ ------ ------ ------ Total 174 195 207 217 185 ====== ====== ====== ====== ======
SJV Gathering System The SJV Gathering System is a proprietary pipeline system that only transports crude oil purchased by entities owned by PAA. As a proprietary pipeline, the SJV Gathering System is not subject to common carrier regulations and does not transport 14 crude oil for third parties. The primary purpose of the pipeline is to gather crude oil from various sources in the San Joaquin Valley and to blend such crude oil along the pipeline system in order to deliver either West Coast Heavy or Mojave Blend into the All American Pipeline. Certain crude streams are segregated and delivered into either the All American Pipeline or to third party pipelines connected to the SJV Gathering System. 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. The SJV Gathering System also includes approximately 586,000 barrels of tank capacity, which has historically been used to facilitate movements along the pipeline system. The SJV Gathering System is operated in conjunction with, and with the same SCADA system used in the operations of the All American Pipeline. PAA also takes measures to protect the pipeline from corrosion and routinely inspects the pipeline using the same procedures and practices employed in the operation of the All American Pipeline. Like the All American Pipeline, the SJV Gathering System was constructed and is maintained in all material respects in accordance with applicable federal, state and local laws and regulations, standards recommended by the American Petroleum Institute and accepted industry standards of practice. 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 and Elk Hills fields. The table below sets forth the historical volumes received into the SJV Gathering System. Year Ended December 31, -------------------------------------- 1998 1997 1996 1995 1994 ------ ------ ------ ------ ------ (barrels in thousands) Total average daily volumes 85 91 67 50 54 To increase utilization and margins relating to the SJV Gathering System, PAA has initiated a wellhead gathering, transportation and marketing program in the San Joaquin Valley. The new program is similar to a program to purchase crude oil from independent producers successfully implemented by the Plains Midstream Subsidiaries in Texas, Oklahoma, Kansas and Louisiana under which volumes increased from 1,300 barrels per day in 1990 to 88,000 barrels per day in 1998. PAA has committed resources to its new gathering program by hiring an additional lease buyer, activating an existing truck unloading station and arranging to make additional connections with other pipeline systems in the San Joaquin Valley, including access into the Pacific Pipeline. In addition, PAA has entered into an arrangement with various parties whereby PAA has reserved up to 40,000 barrels per day of capacity for movements into the Pacific Pipeline, and all crude oil sourced by one such party from the Midway Sunset field will be delivered by PAA into the Pacific Pipeline via the SJV Gathering System. Construction of the Pacific Pipeline, a pipeline system that will service the LA Basin, was completed in early 1999. See "-- Competition". Terminalling and Storage Activities and Gathering and Marketing Activities Terminalling and Storage The Cushing Terminal was constructed in 1993 to capitalize on the crude oil supply and demand imbalance in the Midwest 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 PAA's merchant activities relating to its lease gathering and bulk trading activities. The Ingleside Terminal was constructed in 1979 and purchased by the Plains Midstream Subsidiaries in 1996 to enhance its lease gathering activities in South Texas. The Cushing Terminal has a total storage capacity of two million barrels, comprised of fourteen 100,000 barrel tanks and four 150,000 barrel tanks 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 up to 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. A one million barrel expansion project to add four 250,000 barrel tanks is currently underway at the Cushing Terminal with completion targeted for the second quarter of 1999. 15 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, certain attributes were incorporated into the design of the Cushing Terminal including (i) multiple, smaller tanks to facilitate simultaneous handling of multiple crude varieties in accordance with normal pipeline batch sizes, (ii) dual header systems connecting each tank to the main manifold system to facilitate efficient switching between crude grades with minimal contamination, (iii) bottom drawn sump pumps that enable each tank to be efficiently drained down to minimal remaining volumes to minimize crude contamination and maintain crude integrity, (iv) a mixer on each tank to facilitate blending crude grades to refinery specifications, and (v) 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, PAA believes it is favorably positioned to serve the needs of Midwest refiners to handle increasing varieties of crude transported through the Cushing Interchange. The Cushing Terminal also incorporates numerous environmental and operational safeguards. PAA believes that its terminal is the only one at the Cushing Interchange for 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 above ground pipelines. Like the All American Pipeline and the SJV Gathering System, the Cushing Terminal is operated by a SCADA system 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 floating roof that minimizes air emissions and prevents the possible accumulation of potentially flammable gases between fluid levels and the roof of the tank; and a foam line that, in the event of a fire, is connected to the automated fire water distribution system. 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 a NYMEX delivery point and a cash market hub, the Cushing Interchange serves as the 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 Ingleside Terminal was constructed in 1979 and purchased by the Plains Midstream Subsidiaries in 1996 to enhance its lease gathering activities in South Texas. The Ingleside Terminal is located near the Gulf Coast port of Corpus Christi, Texas. The Ingleside Terminal is comprised of 11 tanks ranging in size from a minimum of 15,000 barrels to a maximum of 50,000 barrels. Three of these tanks are heated, which allows for storage of heavier products. The terminal has access to the receipt of crude oil and refined petroleum products from trucks and barges. Likewise, the terminal can deliver crude oil and refined petroleum products to barges and trucks. PAA leases a barge dock approximately one mile from the Ingleside Terminal and is connected to the dock by four pipelines ranging in size from 8 inches to 12 inches in diameter. The dock lease can be extended in five-year intervals through 2021. PAA's terminalling and storage operations generate revenue through terminalling and storage fees paid by third parties as well as by utilizing the tankage in conjunction with its merchant activities. Storage fees are generated when PAA leases tank capacity to third parties. Terminalling fees, also referred to as throughput fees, are generated when PAA receives crude oil from one connecting pipeline (generally received in batch sizes of 25,000 to 400,000 barrels) and redelivers 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 (which is generally three to ten days). Both terminalling and storage fees are generally earned from (i) refiners and gatherers that segregate or custom blend crudes for refining feedstocks, (ii) pipeline operators, refiners or traders that need segregated tankage for foreign cargoes, (iii) traders who make or take delivery under NYMEX contracts and (iv) producers and resellers that seek to increase their marketing alternatives. The tankage that is used to support PAA's arbitrage activities position PAA to capture margins in a contango market or when the market switches from contango to backwardation. 16 The following table sets forth the daily throughput volumes for PAA's terminalling and storage operations, and quantity of tankage leased to third parties from 1994 through 1998.
Year Ended December 31, --------------------------------------- 1998 1997 1996 1995 1994 ------ ------ ------ ------ ------- (barrels in thousands) Throughput volumes (average daily volumes): Cushing Terminal 69 69 56 43 29 Ingleside Terminal 11 8 3 - - ------ ------ ------ ------ ------- Total 80 77 59 43 29 ====== ====== ====== ====== ======= Storage leased to third parties (monthly aveage volumes): Cushing Terminal 890 414 203 208 464 Ingleside Terminal 260 254 211 - - ------ ------ ------ ------ ------- Total 1,150 668 414 208 464 ====== ====== ====== ====== =======
PAA has committed 1.5 million barrels of its capacity at the Cushing Terminal to storage arrangements with third parties through mid-1999. Gathering and Marketing Activities PAA's gathering and marketing activities are primarily conducted in Louisiana, Texas, Oklahoma and Kansas and include (i) purchasing crude oil from producers at the wellhead and in bulk from aggregators at major pipeline interconnects and trading locations, (ii) transporting such crude oil on its own proprietary gathering assets or assets owned and operated by third parties when necessary or cost effective, (iii) exchanging such 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 (iv) marketing crude oil to refiners or other resellers. For the year ended December 31, 1998, PAA purchased approximately 88,000 barrels per day of crude oil directly at the wellhead. PAA purchases crude oil from producers under contracts that range in term from a thirty-day evergreen to two years. Gathering and marketing activities are characterized by large volumes of transactions with lower margins relative to pipeline and terminalling and storage operations. The following table shows the average daily volume of PAA's lease gathering and bulk purchases from 1995 through 1998. Year Ended December 31, ------------------------------ 1998 1997 1996 1995 ------ ------ ------ ------ (barrels in thousands) Lease gathering 88 71 59 46 Bulk purchases 95 49 32 10 ------ ------ ------ ------ Total volumes 183 120 91 56 ====== ====== ====== ====== 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 PAA's field personnel to purchase and transport the crude oil to market. PAA utilizes pipelines, trucks and barges owned and operated by third parties and PAA's truck fleet and gathering pipelines to transport the crude oil to market. PAA owns approximately 29 trucks, 30 tractor-trailers and 22 injection stations. Pursuant to the Crude Oil Marketing Agreement, PAA is the exclusive marketer/purchaser for all of the Company's equity crude oil production. The Crude Oil Marketing Agreement provides that PAA will purchase for resale at market prices all of the Company's crude oil production for which it will charge a fee of $0.20 per barrel. This fee will be adjusted every three years based upon then existing market conditions. The Crude Oil Marketing Agreement will terminate upon a "change of control" of the Company or the General Partner. Bulk Purchases. In addition to purchasing crude oil at the wellhead from producers, PAA purchases 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. PAA purchases crude oil in bulk when it believes 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 PAA's bulk purchases 17 fluctuate from period to period. PAA's 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. PAA sells its crude oil to major integrated oil companies and independent refiners in various types of sale and exchange transactions, generally at market-responsive prices for terms ranging from one month to three years. As PAA purchases crude oil, it establishes 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, PAA seeks to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. PAA from time to time enters into fixed price delivery contracts, floating price collar arrangements, financial swaps and oil futures contracts as hedging devices. To ensure a fixed price for future production, PAA may sell a futures contract and thereafter either (i) make physical delivery of its crude oil to comply with such contract or (ii) buy a matching futures contract to unwind its futures position and sell its crude oil to a customer. PAA's policy is generally to purchase only crude oil for which it has a market and to structure its sales contracts so that crude oil price fluctuations do not materially affect the gross margin which it receives. PAA does 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 PAA to indeterminable 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. PAA's management monitors crude oil volumes, grades, locations and delivery schedules and coordinates marketing and exchange opportunities, as well as NYMEX hedging positions. This coordination ensures that PAA's NYMEX hedging activities are successfully implemented. Crude Oil Exchanges. PAA pursues exchange opportunities to enhance margins throughout the gathering and marketing process. When opportunities arise to increase its margin or to acquire a grade of crude oil that more nearly matches its delivery requirement or the preferences of its refinery customers, PAA exchanges physical crude oil with third parties. These exchanges are effected through contracts called exchange or buy-sell agreements. Through an exchange agreement, PAA agrees to buy crude oil that differs in terms of geographic location, grade of crude oil or delivery schedule from crude oil it has available for sale. Generally, PAA enters into exchanges to acquire crude oil at locations that are closer to its end markets, thereby reducing transportation costs and increasing its margin. PAA also exchanges its 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 enters 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 its delivery contracts. Producer Services. Crude oil purchasers who buy from producers compete on the basis of competitive prices and highly responsive services. PAA believes that its ability to offer high-quality field and administrative services to producers is a key factor in maintaining volumes of purchased crude oil and obtaining 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 PAA), 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, PAA 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. PAA's merchant activities involve the purchase of crude oil for resale and require significant extensions of credit by PAA's suppliers of crude oil. In order to assure PAA's ability to perform its obligations under crude purchase agreements, various credit arrangements are negotiated with PAA's crude oil suppliers. Such arrangements include open lines of credit directly with PAA and standby letters of credit issued under the Letter of Credit Facility. See "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations--Capital Resources, Liquidity and Financial Condition." 18 When PAA markets crude oil, it must determine the amount, if any, of the line of credit to be extended to any given customer. If PAA determines that a customer should receive a credit line, it must then decide on the amount of credit that should be extended. Since 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 PAA's business. PAA believes its sales are made to creditworthy entities or entities with adequate credit support. Credit review and analysis are also integral to PAA's 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, PAA must determine whether the operator has sufficient financial resources to make such payments and distributions and to indemnify and defend PAA 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 The following table presents certain information with respect to the Company's upstream oil and natural gas producing activities and its midstream marketing, transportation, terminalling and storage activities during the three years ended December 31, 1998, 1997 and 1996:
Years Ended December 31, ------------------------------------------ 1998 1997 1996 --------- ---------- ---------- (in thousands) Sales to unaffiliated customers: Oil and natural gas $ 102,754 $ 109,403 $ 97,601 Marketing, transportation and storage 1,129,689 752,522 531,698 Operating margins: Oil and natural gas(1) $ 51,927 $ 63,917 $ 58,866 Marketing, transportation and storage(2) 38,361 12,480 9,531 Identifiable assets: Oil and natural gas $ 364,059 $ 407,200 $ 307,692 Marketing, transportation and storage 610,208 149,619 122,557
____________________ (1) Consists primarily of oil and natural gas sales less production expenses. (2) Consists primarily of marketing, transportation and storage sales less purchases, transportation and storage expenses. Includes approximately $2.5 million of operating profit attributable to contango market transactions in 1998 and in 1997. Operating profits as a percentage of sales are significantly lower for the Company's marketing, transportation and storage activities than for its oil and natural gas producing activities because the cost of crude oil purchased for resale is higher, as a percentage of sales price, than the Company's cost to produce oil and natural gas. See "-- Midstream Activities". General The Company was incorporated under the laws of the State of Delaware in 1976. The Company's executive offices are located at 500 Dallas, Suite 700, Houston, Texas 77002, and its telephone number is (713) 654-1414. Product Markets and Major Customers The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and natural gas. Historically, the markets for oil and natural gas have been volatile and are likely to continue to be volatile in the future. The prices received by the Company for its oil and natural gas production and the levels of such production are subject to wide fluctuations and depend on numerous factors beyond the Company's control, including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. The Company's 1998 earnings were adversely affected by low crude oil prices throughout 1998. See "Item 7, Management's 19 Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices". In order to manage its exposure to price risks in the marketing of its oil and natural gas, the Company from time to time enters into fixed price delivery contracts, floating price collar arrangements, financial swaps and oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, the Company may sell a futures contract and thereafter either (i) make physical delivery of its product to comply with such contract or (ii) buy a matching futures contract to unwind its futures position and sell its 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 the Company to the risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase or deliver the contracted quantities of oil or natural gas, or a sudden, unexpected event materially impacts oil or natural gas prices. Such contracts may also restrict the ability of the Company to benefit from unexpected increases in oil and natural gas prices. See "Item 2, Properties -- Oil and Natural Gas Reserves". Substantially all of the Company's California crude oil and natural gas production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the Company having to find transportation alternatives, increased transportation costs to the Company or involuntary curtailment of a significant portion of its crude oil and natural gas production. Certain of the Company's 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 the Company's natural gas, may in the future adversely affect the Company's ability to sell its natural gas production. All of the Company's natural gas production in California is produced as a by-product of the Company's crude oil production. As a result of high inert content, the Company's gas production in the Montebello Field is difficult to market and currently is delivered for no value. To ensure that the Company is able to develop and produce its oil reserves without restriction due to lack of markets, the Company has made arrangements with the former owner of the Montebello Field to take its natural gas production volumes at no incremental value when the Company is unable to find a market for the gas. The Company has improved the quality of the gas through upgrading and refining the existing gas collection system, as well as adding additional processing capacity. The Company believes that this will enable it to obtain an alternate market for the gas production in 1999, although such market cannot be assured. Before 1985, substantially all of the Company's natural gas production was sold directly to pipeline companies which were responsible for resale and transportation of the natural gas to end-users. Since that time, however, with the adoption of various orders by the FERC (See "-- Regulation -- Transportation and Sale of Natural Gas") and the deregulation of natural gas pursuant to the Natural Gas Policy Act of 1978 ("NGPA") and the Natural Gas Wellhead Decontrol Act of 1989 (the "Decontrol Act"), the FERC has actively promoted competition in the nationwide market for natural gas and has encouraged pipelines to significantly reduce their role as merchants of natural gas and to make transportation services available on an "open-access", nondiscriminatory basis. Since these regulatory initiatives were begun, natural gas producers such as the Company have been able to sell their natural gas supplies directly to utilities and other end-users. In addition to the regulatory changes discussed above, deregulation of natural gas prices under the NGPA and the Decontrol Act has increased competition and volatility of natural gas prices. Since demand for natural gas is generally highest during winter months, prices received for the Company's natural gas are subject to seasonal variations and other fluctuations. All of the Company's natural gas production is currently sold under various arrangements at spot indexed prices. In certain instances, the Company enters into financial arrangements to hedge its exposure to spot price fluctuations. See "Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices" and "Item 2, Properties -- Production and Sales". Sales to Sempra Energy Trading Corporation ("Sempra") (formerly AIG Trading Corporation) and Koch Oil Company ("Koch") accounted for 27% and 15%, respectively, of the Company's total revenue (exclusive of interest and other income) during 1998. Customers accounting for more than 10% of total revenue for 1997 and 1996 were as follows: 1997 -- Koch -27% and Sempra - 11%, 1996 -- Koch - - - 16% and Basis Petroleum, Inc. (formerly Phibro Energy USA, Inc.) - 11%. No other single customer accounted for as much as 10% of total sales during 1998, 1997 or 1996. Additionally during 1998, Tosco Refining Company and Scurlock Permian LLC accounted for approximately 50% and 17%, respectively, of the Company's oil and gas sales. See "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations". 20 Competition Oil and Natural Gas Producing Activities The Company's 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 the Company's larger competitors possess and employ financial and personnel resources substantially greater than those available to the Company. Such companies are able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will depend on its 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 The All American Pipeline encounters competition from foreign oil imports and other pipelines that serve the California market and the refining centers in the Midwest and on the Gulf Coast. Construction of the Pacific Pipeline, a new pipeline connecting the San Joaquin Valley to refinery markets in the LA Basin area, was completed in the first quarter of 1999. The Pacific Pipeline is expected to compete with PAA for transportation volumes. PAA expects that certain volumes currently transported on the All American Pipeline may be redirected to Los Angeles on such pipeline. Competition among common carrier pipelines is based primarily on transportation charges, access to producing areas and demand for the crude oil by end users. PAA believes that high capital requirements, environmental considerations and the difficulty in acquiring rights of way and related permits make it unlikely that a competing pipeline system comparable in size and scope to the All American Pipeline will be built in the foreseeable future. The Company faces intense competition in its terminalling and storage activities and gathering and marketing activities. Its 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 PAA's and control substantially greater supplies of crude oil. Regulation The Company's operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is constantly reviewed for amendment and expansion. Many departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil and natural gas 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 and natural gas industry increases the Company's cost of doing business and, consequently, affects its profitability. However, the Company does not believe that it is affected in a significantly different manner by these regulations than are its competitors in the oil and natural gas industry. Due to the myriad and complex federal and state statutes and regulations which may affect the Company directly or indirectly, the following discussion of certain statutes and regulations should not be relied upon as an exhaustive review of all regulatory considerations affecting the Company's operations. OSHA The Company is also subject to the requirements of the Federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The Company believes that its operations substantially comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated. Commodities Regulation The Company's hedging activities are subject to constraints imposed under the Commodity Exchange Act and the rules of the NYMEX. The futures and options contracts that are traded on the NYMEX are subject to strict regulation by the Commodity Futures Trading Commission. 21 Trucking Regulation The Company operates a fleet of trucks to transport crude oil as a private carrier. As a private carrier, the Company is subject to certain motor carrier safety regulations issued by the Department of Transportation ("DOT"). 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. The Company is also subject to OSHA with respect to its trucking operations. Pipeline Regulation PAA's pipelines are subject to regulation by the DOT 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 PAA and other pipeline operators to comply with regulations issued 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 (the "Pipeline Safety Act") amends the HLPSA in several important respects. It requires the Research and Special Programs Administration ("RSPA") of DOT 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 DOT of pipeline operator qualification rules requiring minimum training requirements for operators, and requires that pipeline operators provide maps and records to RSPA. It also authorizes RSPA 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. PAA believes that its pipeline operations are in substantial compliance with applicable HLPSA and Pipeline Safety Act requirements. Nevertheless, significant expenses could be incurred 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. PAA does not anticipate any significant problems in complying with applicable state laws and regulations in those states in which it operates. Transportation and Sale of Crude Oil In October 1992 Congress passed the Energy Policy Act of 1992 ("Energy Policy Act"). 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: (i) 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; (ii) the complainant was contractually barred from challenging the rate prior to enactment; or (iii) a provision of the tariff is unduly discriminatory or preferential. 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 22 for new services can be established through a cost-of-service proceeding or through an uncontested agreement between the pipeline and 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. In a recent 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. There is also pending at the FERC a proceeding 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 September 25, 1997, the administrative law judge in the Santa Fe Proceeding issued an initial decision addressing various aspects of the tax allowance issue as it affects publicly traded partnerships, as well as various technical issues involving the application of the FERC oil pipeline ratemaking methodology. The administrative law judge's initial decision in the Santa Fe Proceeding is currently pending review by the FERC. In such review, it is possible that the FERC could alter its current rulings on the tax allowance issue or on the application of the FERC oil pipeline ratemaking methodology. The FERC generally has not investigated rates, such as those currently charged by PAA, 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 PAA's gross margins on transportation are produced by rates that are either grandfathered or set by agreement of the parties. The rates for substantially all of the crude oil transported from California to West Texas are grandfathered and not subject to decreases through the application of indexing. 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, PAA believes that the rates now in effect can be sustained, although no assurance can be given that the rates currently charged by PAA would ultimately be upheld if challenged. In addition, PAA does not believe that an adverse determination on the tax allowance issue in the Santa Fe Proceeding would have a detrimental impact upon the current rates charged by PAA. Transportation and Sale of Natural Gas The FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of natural gas produced by the Company, as well as the revenues received by the Company for sales of such natural gas. Since the latter part of 1985, the FERC has adopted policies intended to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. The FERC's most recent action in this area, Order No. 636, reflected the FERC's finding that, under the then-existing regulatory structure, interstate pipelines and other natural gas merchants, including producers, did not compete on a "level playing field" in selling natural gas. Order No. 636 instituted individual pipeline service restructuring proceedings, designed specifically to "unbundle" those services (e.g., transportation, sales and storage) provided by many interstate pipelines so that buyers of natural gas may secure natural gas supplies and delivery services from the most economical source, whether interstate pipelines or other parties. The FERC has issued final orders in all of the restructuring proceedings and has announced its intention to reexamine certain of its transportation-related policies, including the appropriate manner in which interstate pipelines release capacity under Order No. 636 and, more recently, the price which shippers can charge for their released capacity. The FERC has also adopted a new policy regarding the use of non-traditional methods of setting rates for interstate natural gas pipelines in certain circumstances as alternatives to cost of service based rates. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. The Company cannot predict what action the FERC will take in the reexamination of its transportation-related policies, nor can it accurately predict whether the FERC's actions will achieve its stated goal of increasing competition in domestic natural gas 23 markets. However, the Company does not believe that it will be treated materially differently than other natural gas producers and marketers with which it competes. Although the FERC's actions, such as Order No. 636, do not regulate natural gas producers such as the Company, these 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 the Company's business or operations. On a prospective basis, however, such orders may substantially increase the burden on the producers and transporters to nominate and deliver on a daily basis a specified volume of natural gas. Producers and transporters which deliver deficient volumes or volumes in excess of such daily nominations could be subject to additional charges by the pipeline carriers. The United States Court of Appeals for the District of Columbia Circuit has affirmed the FERC's Order No. 636 restructuring rule and remanded certain issues for further explanation or clarification. Numerous petitions seeking judicial review of the individual pipeline restructuring orders are currently pending in that Court. Although it is difficult to predict when all appeals of pipeline restructuring orders will be completed or their impact on the Company, the Company does not believe that it will be affected by the restructuring rule and orders any differently than other natural gas producers and marketers with which it competes. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective or their effect, if any, on the Company's 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 the Company's cost of doing business and, consequently, affects its profitability and cash flow. Inasmuch as laws and regulations are frequently expanded, amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such regulations. Regulation of Production The production of 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 the Company owns and operates 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 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 the Company can produce from its wells and to limit the number of wells or the locations at which the Company 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 the Company's operations and costs. In particular, the Company's exploration, exploitation and production operations, its activities in connection with storage and transportation of crude oil and other liquid hydrocarbons and its use of facilities for treating, processing or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation. As with the industry generally, compliance with existing and anticipated regulations increases the Company's overall cost of business. Such areas affected include unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water, capital costs to drill exploration and development wells due to solids control and capital costs to construct, maintain and upgrade equipment and facilities. While these regulations affect the Company's capital expenditures and earnings, the Company believes that such regulations do not affect its competitive position in that the operations of its competitors that comply with such regulations are similarly affected. Environmental regulations have historically been subject to frequent change by regulatory authorities, and the Company is unable to predict the ongoing cost to it of complying with these laws and regulations or the future impact of such regulations on its operation. A discharge of hydrocarbons or hazardous substances into the environment could, to the extent such event is not insured, subject the Company 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. 24 Although the Company obtained environmental studies on its properties in California, the Sunniland Trend and the Illinois Basin, and the Company believes 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, the Company 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 the Company agreed to excavate and remediate nonhazardous crude oil contaminated soils. The Company is obligated to construct and operate (for the next 12 years) a minimum of five acres of bioremediation cells for crude oil contaminated soils designated for excavation and treatment by Chevron. While the Company believes that it does not have any material obligations for operations conducted prior to Stocker's acquisition of the properties from Chevron, other than its 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 it 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 the Sunniland Trend Properties is located within the Big Cypress National Preserve and the Company's 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 the Company's 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 the Company restore the surface property affected by its drilling and production operations upon cessation of these activities. The Company does 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 Acquisition 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 the Company's operations and its planned activities or future commercial and/or residential development, the Company believes that it will be able to operate the existing wells and realize the reserve potential identified in its 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 United States. In the event of an oil spill into such waters, substantial liabilities could be imposed upon the Company. States in which the Company operates have also enacted similar laws. Regulations are currently being developed under OPA and state laws that may also impose additional regulatory burdens on the Company. The FWPCA imposes restrictions and strict controls regarding the discharge of produced waters and other oil and natural gas wastes into navigable waters. Permits must be obtained to discharge pollutants to state and federal waters. The FWPCA provides for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and, along with the OPA, imposes substantial potential liability for the costs of removal, remediation and damages. State laws for the control of water pollution also provide varying civil, criminal and administrative penalties and liabilities in the case of a discharge of petroleum or its derivatives into state waters. The EPA has promulgated regulations that require many oil and natural gas production operations to obtain permits to discharge storm water runoff. At some facilities, such as the Sunniland Trend Properties, the Company eliminated this permit requirement by collecting all potentially contaminated storm water and disposing of it through the Company's underground injection control ("UIC") disposal wells. At other facilities, the Company has applied for and obtained any necessary storm water discharge permits, and is currently in substantial compliance with applicable permit conditions. The Company believes that compliance with existing 25 permits and compliance with foreseeable new permit requirements will not have a material adverse effect on the Company's financial condition or results of operations. Air Emissions. The operations of the Company are subject to the Federal Clean Air Act and comparable state and local statutes. The Company believes that its operations are in substantial compliance with such statutes in all states in which they 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 United States 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 particular, the Company's LA Basin properties are located in an "extreme" non-attainment area for ozone. This classification will force the local air quality regulatory authority, the South Coast Air Quality Management District, to adopt stringent controls on all emissions of nitrogen oxide and volatile organic compounds. As a result of these future regulations, the Company may incur future capital expenditures to reduce air emissions from the LA Basin production facilities. In addition, the 1990 Federal Clean Air Act Amendments include a new operating permit for major sources ("Title V permits"), and several of the Company's facilities may require permits under this new program. Although no assurances can be given, the Company believes implementation of the 1990 Federal Clean Air Act Amendments will not have a material adverse effect on the Company's financial condition or results of operations. Solid Waste. The Company generates 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. RCRA also governs the disposal of hazardous wastes. At present, the Company is not required to comply with a substantial portion of the RCRA requirements because the Company's operations generate minimal quantities of hazardous wastes. However, it is anticipated 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 may result in additional capital expenditures or operating expenses by the Company. Superfund. 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 its ordinary operations, the Company may generate waste that may fall within CERCLA's definition of a "hazardous substance". The Company 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 or released into the environment. The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and natural gas. Although the Company has 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 the Company or on or under other locations where such 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 the Company's control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company 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. PAA believes that its operations are in substantial compliance with such regulations. 26 Federal Taxation For federal income tax purposes, PAAI is the General Partner of PAA, holding a direct and indirect ownership of approximately 57% 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. As a result of the formation of PAA, significant taxable income was generated, allowing the Company to utilize certain net operating losses ("NOL") previously subject to separate return limitation year ("SRLY") restrictions. As a result, the Company no longer has any net operating losses subject to the SRLY rules. At December 31, 1998, the Company and its 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 NOL carryforwards of approximately $139.7 million and approximately $128.3 million of alternative minimum tax ("AMT") net operating loss carryforwards available as a deduction against future AMT income. In addition, the Company had approximately $.3 million of investment tax credit carryforwards, $1.3 of AMT credits and $7.0 million of percentage depletion carryforwards at December 1, 1998. The NOL carryforwards expire from 2003 through 2011. The value of these carryforwards depends on the ability of the Company 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. The ability of the Company to utilize NOL and investment tax credit carryforwards to reduce future federal taxable income and federal income tax of the Company 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 the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% ("Ownership Change") in the beneficial ownership of the Company. 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 (i) the fair market value of the equity of the Company multiplied by (ii) 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, the Company does not believe that an Ownership Change has occurred as of December 31, 1998. Equity transactions after the date hereof by the Company or by 5% stockholders (including relatively small transactions and transactions beyond the Company's 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 the Company's 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 The Company must continually acquire, explore for, develop or exploit new oil and natural gas reserves to replace those produced or sold. Without successful drilling, acquisition or exploitation operations, the Company's oil and natural gas reserves and revenues will decline. Drilling activities are subject to numerous risks, including the risk that no commercially viable 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 -- 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 the Company's oil and natural gas production also depends on a number of factors, including the demand for and supply of 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 the Company's California crude oil and natural gas production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could cause the Company to seek transportation alternatives, which in turn could result in increased transportation costs to the Company or involuntary curtailment of a significant portion of its crude oil and natural gas production. The Company's operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, cratering, oil spills and fires, each of which could result in damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. The relatively deep drilling conducted by the Company from time to time involves increased drilling risks of high pressures and mechanical difficulties, including stuck pipe, collapsed casing and separated cable. The Company's 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 the Company maintains insurance coverage considered to be customary in the industry, it is 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 the Company's 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. PAA maintains insurance of various types that it considers to be adequate to cover its operations and properties. The insurance covers all of PAA's assets in amounts considered reasonable. The insurance policies are subject to deductibles that PAA considers reasonable and not excessive. PAA's 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, PAA's 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 PAA's operations and financial condition. PAA believes that it is adequately insured for public liability and property damage to others with respect to its operations. With respect to all of its coverage, no assurance can be given that PAA will be able to maintain adequate insurance in the future at rates it considers reasonable. The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and natural gas. Historically, the prices for oil and natural gas have been volatile and are likely to continue to be volatile in the future. The price received by the Company for its oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors beyond the Company's control, including seasonality, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other 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 oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Almost all of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price at December 31, 1998, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $12.05 per barrel. Such price was the lowest year-end price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. Although the Company is not currently experiencing any significant involuntary curtailment of its crude oil or natural gas production, market, logistic, economic and regulatory factors may in the future materially affect the Company's ability to sell its production. In order to manage its exposure to price risks in the marketing of its oil and natural gas, the Company from time to time enters into fixed price delivery contracts, floating price collar arrangements, financial swaps and oil and natural gas futures contracts as hedging devices. To ensure a fixed price for future production, the Company may sell a futures contract and thereafter either (i) make physical delivery of its product to comply with such contract or (ii) buy a matching futures contract to unwind its futures position and sell its 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 the Company to the risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase or deliver the contracted quantities of oil or natural gas, or a sudden, unexpected event materially impacts oil or natural gas prices. Such contracts may also restrict the ability of the Company to benefit from unexpected increases in oil and natural gas prices. See "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources, 28 Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices" and "Item 7A, Quantitative and Qualitative Disclosures about Market Risks". Title to Properties The Company's 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. The Company does not believe that any of these burdens materially interferes with the use of such properties in the operation of its business. The Company believes that it has generally satisfactory title to or rights in all of its producing properties and other assets. 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 the Company's 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. Permits have been obtained 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. Permits have also been obtained 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. Some of the leases, easements, rights-of-way, permits and licenses transferred to PAA upon its formation in 1998 required the consent to transfer of the grantor of such rights, which in certain instances is a governmental entity. The Company believes that it has obtained such third-party consents, permits and authorizations that are sufficient for the transfer to the Company of the assets necessary for the Company to operate its business in all material respects as described in this report. With respect to any consents, permits or authorizations which have not yet been obtained, the Company believes 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 the Company's business. If any such consents are not so obtained, the Company will enter into other agreements, or take such other action as may be necessary to ensure that the Company has the assets and concomitant rights necessary to enable it to operate the Company's business in all material respects as described in this Report. Employees As of March 1, 1999, the Company had 370 full-time employees, none of whom is represented by any labor union. Approximately 178 of such full-time employees are field personnel involved in oil and natural gas producing activities, trucking and transport activities and crude oil terminalling and storage activities. Approximately 210 employees spend the substantial majority of their time on the business of PAA. Item 2. PROPERTIES The Company is an independent energy company engaged in the acquisition, exploitation, development, exploration and production of crude oil and natural gas. Through its majority ownership in PAA, the Company is engaged in the midstream activities of marketing, transportation, terminalling and storage of crude oil. The Company's upstream oil and natural gas activities are focused in California, the Sunniland Trend and the Illinois Basin. The Company's midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. The Company's upstream operations contributed approximately 58% of the Company's EBITDA for the fiscal year ending December 31, 1998, while the Company's midstream activities accounted for 42%. The Company conducts its upstream operations in each of its three core areas through wholly owned subsidiaries. The California Properties are operated by Stocker, the Sunniland Trend properties are operated by Calumet and the Illinois Basin Properties are operated by Plains Illinois. See "Item 1, Business" for a discussion of the Company's acquisition, development, exploitation and exploration activities and midstream businesses. 29 Oil and Natural Gas Reserves The following tables set forth certain information with respect to the Company's reserves based upon reserve reports prepared by the independent petroleum consulting firms of H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., Ryder Scott Company and System Technology Associates, Inc. Such reserve 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, ------------------------------------------------------------------------------------ 1998 1997 1996 ------------------------------- ------------------------ ----------------------- OIL GAS OIL GAS OIL GAS (BBL) (MCF) (BBL) (MCF) (BBL) (MCF) ------------------------------- ------------------------ ----------------------- (IN THOUSANDS) Proved Reserves Beginning balance 151,627 60,350 115,996 37,273 94,408 43,110 Revision of previous estimates (46,282) 2,925 (16,091) 3,805 19,424 6,641 Extensions, discoveries, improved recovery and other additions 14,729 29,306 17,884 8,126 8,179 1,294 Sale of reserves in-place - (2,799) (26) (547) (5) (12,491) Purchase of reserves in-place 7,709 - 40,764 14,566 45 862 Production (7,575) (3,001) (6,900) (2,873) (6,055) (2,143) -------- -------- -------- ------- -------- -------- Ending balance 120,208 86,781 151,627 60,350 115,996 37,273 ======== ======== ======== ======= ======== ======== PROVED DEVELOPED RESERVES Beginning balance 99,193 38,233 86,515 25,629 67,266 29,397 ======== ======== ======== ======= ======== ======== Ending balance 73,264 58,445 99,193 38,233 86,515 25,629 ======== ======== ======== ======= ======== ========
The following table sets forth the Present Value of Proved Reserves as of December 31, 1998, 1997 and 1996. 1998 1997 1996 ------- ------ ------- (in thousands) Proved developed $ 185,961 $ 386,463 $ 574,686 Proved undeveloped 40,982 124,530 190,088 -------- -------- -------- Total Proved $ 226,943 $ 510,993 $ 764,774 ======== ======== ======== 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 the control of the Company. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of 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 oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future 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 oil and natural gas reserves attributable to the Company's 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 the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The benchmark NYMEX crude oil price received by the Company at December 31, 1998, 1997, and 1996 upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such dates were based, was $12.05 per barrel, $18.34 per barrel and $25.92 per barrel, respectively. The crude oil price at December 31, 1998, was the lowest year-end price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. Revisions of previous estimates set forth above include downward price related revisions of 52 MMBbls and 16 MMBbls in 1998 and 1997, respectively, and positive price related revisions of 10 MMBbls in 1996. See "Item 7, Management's Discussion 30 and Analysis of Financial Condition and Results of Operations --Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices". In accordance with the SEC guidelines, the reserve engineers' estimates of future net revenues from the Company's properties and the present value thereof are made using 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, 1998, is based on the NYMEX Crude Oil Price received by the Company of $12.05 per barrel with variations therefrom based on location and grade of crude oil. The Company has entered into various arrangements to fix the NYMEX Crude Oil Price for a significant portion of its crude oil production. On December 31, 1998, these arrangements provided for a NYMEX Crude Oil Price for 9,000 barrels per day from January 1, 1999, through December 31, 1999, at approximately $18.25 per barrel. Since December 31, 1998, the Company has entered into additional arrangements, which provide for a NYMEX Crude Oil Price for 2,000 barrels per day from January 1, 2000, through December 31, 2000, at $15.30 per barrel. Location and quality differentials attributable to the Company's properties are not included in the foregoing prices. Arrangements in effect at December 31, 1998, 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, 1998, were $7.96 per barrel of crude oil, condensate and natural gas liquids and $1.68 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, 1997, the Company has not filed any estimates of total proved net oil or natural gas reserves with any federal authority or agency other than the SEC. See Note 18 to the Company's Consolidated Financial Statements appearing elsewhere in this Report for certain additional information concerning the proved reserves of the Company. Productive Wells and Acreage As of December 31, 1998, the Company had working interests in 1,727 gross (1,726 net) active oil wells. The following table sets forth certain information with respect to the developed and undeveloped acreage of the Company as of December 31, 1998.
DECEMBER 31, 1998 -------------------------------------------------------------------------------------- DEVELOPED ACRES (1) UNDEVELOPED ACRES (2) --------------------------------------- --------------------------------------- GROSS NET GROSS NET(3) ---------------- ---------------- ---------------- ---------------- California (4) 5,896 5,824 460 460 Florida (5) 12,192 12,192 82,804 78,650 Illinois 16,412 14,410 16,906 8,428 Indiana 1,155 854 1,280 575 Kansas - - 48,147 37,807 Kentucky - - 1,321 521 Louisiana - - 4,875 4,858 ---------------- ---------------- ---------------- ---------------- Total 35,655 33,280 155,793 131,299 ================ ================ ================ ================
_______________________ (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 4% of total net undeveloped acres are covered by leases that expire from 1999 through 2002. (4) Does not include 9,000 acres covered by a farmout from Chevron, in which the Company owns a 50% interest. (5) Does not include approximately 800,000 acres covered by the Exploration Agreement entered into in February 1998 or 29,000 gross (28,000 net) acres under a seismic option. See "Item 1, Exploration -- Current Exploration Projects -- Sunniland Trend". 31 Drilling Activities Certain information with regard to the Company's drilling activities during the years ended December 31, 1998, 1997 and 1996 is set forth below:
YEAR ENDED DECEMBER 31, ----------------------------------------------------------------------------------------------------------- 1998 1997 1996 --------------------------------- ---------------------------------- ------------------------------ GROSS NET GROSS NET GROSS NET -------------- -------------- -------------- --------------- --------------- ---------- Exploratory Wells: Oil - - 2.00 2.00 - - Natural gas - - - - - - Dry - - - - 2.00 0.63 -------------- -------------- -------------- --------------- --------------- ---------- Total - - 2.00 2.00 2.00 0.63 ============== ============== ============== =============== =============== ========== Development Wells: Oil 76.00 76.00 58.00 57.06 24.00 24.00 Natural gas - - - - - - Dry - - - - - - -------------- -------------- -------------- --------------- --------------- ---------- Total 76.00 76.00 58.00 57.06 24.00 24.00 ============== ============== ============== =============== =============== ========== Total Wells: Oil 76.00 76.00 60.00 59.06 24.00 24.00 Natural gas - - - - - - Dry - - 2.00 0.63 -------------- -------------- -------------- --------------- --------------- ---------- Total 76.00 76.00 60.00 59.06 26.00 24.63 ============== ============== ============== =============== =============== ==========
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 oil and natural gas production attributable to the Company's 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, 1998, 1997 and 1996.
YEAR ENDED DECEMBER 31, ----------------------------------------------------------- 1998 1997 1996 ------------------- --------------- --------------- (IN THOUSANDS EXCEPT PER UNIT DATA) Production: Crude oil and natural gas liquids (Bbls) 7,574 6,900 6,055 Natural gas (Mcf) 3,001 2,873 2,143 BOE 8,075 7,379 6,412 Revenue: Crude oil and natural gas liquids $ 98,664 $ 104,988 $ 95,224 Natural gas 4,090 4,415 2,377 -------------- ----------- ---------- Total $ 102,754 $ 109,403 $ 97,601 ============== =========== ========== Average sales price: Crude oil and natural gas liquids (Bbls) $ 13.03 $ 15.22 $ 15.73 Natural gas (Mcf) $ 1.36 $ 1.54 $ 1.11 Per BOE $ 12.73 $ 14.83 $ 15.22 Production expenses per BOE $ 6.29 $ 6.16 $ 6.04
PAA Properties See description of PAA's properties under "Item 1, Business -- Midstream Activities". 32 Item 3. LEGAL PROCEEDINGS On July 9, 1987, 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, a wholly owned subsidiary of the Company, 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 the Company's oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. The Company has reached an agreement in principle with all parties to settle this case. In consideration for full and final settlement, and dismissal with prejudice of all issues in this case, the Company has agreed to pay to the defendants the total sum of $100,000, and release certain royalty amounts held in suspense and in the court registry during the pendency of this case. Finalization of this settlement has been delayed due to disputes over certain title issues. Motions have been filed requesting the Court to rule on the disputes, but no hearing date has been set. The Company does not believe that the disputes will adversely affect the settlement reached between the Company and the defendants. The Company, in the ordinary course of business, is a claimant and/or a defendant in various other legal proceedings in which its exposure, individually and in the aggregate, is not considered material to the Company. 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. Executive Officers of the Company Information regarding the executive officers of the Company 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 40, has been President, Chief Executive Officer and a director of the Company 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 47, has been Executive Vice President and Chief Operating Officer-Upstream since May 1998. He was Senior Vice President of the Company from 1991 to 1998. He was Vice President-Corporate Development of the Company from 1984 to 1991 and Special Assistant-Corporate Planning from 1982 to 1984. Cynthia A. Feeback, Assistant Treasurer, Officer Since 1993 Controller and Principal Accounting Officer Ms. Feeback, age 41, has been Assistant Treasurer, Controller and Principal Accounting Officer since May 1998. She was Controller and Principal Accounting Officer of the Company from 1993 to 1998. She was Controller of the Company from 1990 to 1993 and Accounting Manager from 1988 to 1990. Phillip D. Kramer, Executive Vice President, Officer Since 1987 Chief Financial Officer and Treasurer Mr. Kramer, age 43, has been Executive Vice President, Chief Financial Officer and Treasurer since May 1998. He was Senior Vice President and Chief Financial Officer of the Company from May 1997 to May 1998. He was Vice President and 33 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 51, has been Vice President and General Counsel of the Company since 1985 and Corporate Secretary since 1988. Harry N. Pefanis, Executive Vice President Officer Since 1988 Mr. Pefanis, age 41, 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 of the Company since 1988. From 1987 to 1988 he was Manager of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate Planning for the Company. Mr. Pefanis is also President and Chief Operating Officer of Plains All American Inc. Mary O. Peters, Vice President - Administration Officer Since 1991 and Human Resources Ms. Peters, age 50, has been Vice President-Administration and Human Resources since 1991. She was Manager of Office Administration of the Company from 1984 to 1991. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS The Company's 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 25, 1999, was 1,353. 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 ---------- --------- 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 1997: 1st Quarter $ 18 1/4 $ 12 2nd Quarter 15 3/16 11 7/8 3rd Quarter 18 1/2 15 4th Quarter 20 3/4 15 7/8 The Company has not paid cash dividends on shares of the Common Stock since the Company's inception and does not anticipate paying any cash dividends on the Common Stock in the foreseeable future. In addition, the Company is restricted by provisions of the indenture governing the issue of $200 million 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and prohibited by the Company's $225 million revolving credit facility (the "Revolving Credit Facility") from paying dividends on the Common Stock. On October 1, 1998, the Company paid a dividend on its Series E Preferred Stock for the period from July 29, 1998 through September 30, 1998. The dividend amount of approximately $1.4 million was paid by issuing 2,824 additional shares of the Series E Preferred Stock. After payment of such dividend, there were 172,824 shares of the Series E Preferred Stock outstanding with a liquidation value, including accrued dividends through December 31, 1998, of approximately $88.5 million. 34 Item 6. SELECTED FINANCIAL DATA The following selected historical financial information was derived from, and is qualified by reference to, the Consolidated Financial Statements of the Company, 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".
YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 1998 1997 1996 1995 1994 ---------- --------- --------- --------- --------- (IN THOUSANDS, EXCEPT PER SHARE INFORMATION) Statement of Income Data: Revenues: Oil and natural gas sales $ 102,754 $ 109,403 $ 97,601 $ 64,080 $ 57,234 Marketing, transportation, storage and terminalling revenues 1,129,689 752,522 531,698 339,826 199,239 Interest and other income 61,649 (1) 319 309 319 223 ---------- --------- --------- --------- --------- Total revenue 1,294,092 862,244 629,608 404,225 256,696 ---------- --------- --------- --------- --------- Expenses: Production expenses 50,827 45,486 38,735 30,256 27,220 Marketing, transportation, storage and terminalling expenses 1,091,328 740,042 522,167 333,460 193,049 General and administrative 10,778 8,340 7,729 7,215 6,966 Depreciation, depletion and amortization 31,020 23,778 21,937 17,036 16,305 Reduction of carrying cost of oil and natural gas properties 173,874 (2) - - - - Interest expense 35,730 22,012 17,286 13,606 12,585 Litigation settlement - - 4,000(3) - - ---------- --------- --------- --------- --------- Total expenses 1,393,557 839,658 611,854 401,573 256,125 ---------- --------- --------- --------- --------- Income (loss) before income taxes, extraordinary item and minority interest (99,465) 22,586 17,754 2,652 571 Minority interest 1,809 - - - - Income tax expense (benefit): Current 862 352 - - - Deferred (43,582) 7,975 (3,898) - - ---------- --------- --------- --------- --------- Income (loss) before extraordinary item (58,554)(2) 14,259 21,652 2,652 571 Extraordinary item, net of tax benefit - - (5,104)(4) - - ---------- --------- --------- --------- --------- Net income (loss) (58,554)(2) 14,259 16,548 2,652 571 Less: cumulative preferred stock dividends 4,762 163 - - - ---------- --------- --------- --------- --------- Net income (loss) applicable to common shareholders $ (63,316)(2) $ 14,096 $ 16,548 $ 2,652 $ 571 ========== ========= ========= ========= ========= Earnings (loss) per common share - basic: Before extraordinary item $ (3.77) $ 0.85 $ 1.32 $ 0.19 $ 0.04 Extraordinary item, net of income taxes - - (0.31) - - ---------- --------- --------- --------- --------- $ (3.77) $ 0.85 $ 1.01 $ 0.19 $ 0.04 ========== ========= ========= ========= ========= Earnings (loss) per common share - assuming dilution: Before extraordinary item $ (3.77) $ 0.77 $ 1.23 $ 0.16 $ 0.04 Extraordinary item, net of income taxes - - (0.29) - - ---------- --------- --------- --------- --------- $ (3.77) $ 0.77 $ 0.94 $ 0.16 $ 0.04 ========== ========= ========= ========= ========= OTHER FINANCIAL DATA: Cash flow from operations (5) $ 42,033 $ 46,233 $ 39,942 $ 19,688 $ 16,876 EBITDA (6) 80,344 68,376 56,977 33,294 29,461 Net cash provided by operating activities 37,630 30,307 39,008 16,984 18,369 Net cash used in investing activities 483,422 107,634 52,496 64,398 40,158 Net cash provided by financing activities 448,622 78,524 9,876 52,252 19,297 YEAR ENDED DECEMBER 31, ------------------------------------------------------------ 1998 1997 1996 1995 1994 ---------- --------- --------- --------- --------- (IN THOUSANDS) BALANCE SHEET DATA: Cash and cash equivalents $ 6,544 $ 3,714 $ 2,517 $ 6,129 $ 2,791 Working capital deficit (13,941) (6,011) (4,843) (4,749) (4,465) Property and equipment, net 661,726 413,308 311,040 280,538 217,602 Total assets 974,267 556,819 430,249 352,046 266,904 Long-term debt 431,983 285,728 225,399 205,089 149,600 Other long-term liabilities 13,967 5,107 2,577 1,547 3,754 Redeemable preferred stock 88,487 - - - 20,937 Total stockholders' equity 72,962 133,193 95,572 77,029 46,462
(footnotes on following page) 35 ________________________ (1) Includes a $60.8 million non-cash gain recognized by the Company upon the formation of PAA. (2) Includes a $173.9 million pre-tax ($109.0 million after tax) non-cash charge related to a writedown of the capitalized costs of the Company's proved 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". (3) Represents charge related to the settlement of two lawsuits filed in 1992 and 1993. See "Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations". (4) Relates to the early redemption in March 1996 of the Company's 12% Senior Subordinated Notes due 1999. (5) Net cash provided by operating activities after minority interest but before changes in assets and liabilities and other non-cash items. (6) EBITDA means earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items. 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. 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. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General On November 23, 1998, PAA, through which the Company's midstream activities are conducted, completed its initial public offering of 13.1 million common units representing limited partner interests. PAA's results are consolidated into the Company's results with the public's 43% ownership reflected as a minority interest deduction from income. PAA was formed to acquire the midstream crude oil business and assets of the Company, including the All American Pipeline and the SJV Gathering System, which the Company purchased from Goodyear in July 1998. See "-- Capital Resources, Liquidity and Financial Condition". The assets, liabilities and results of operations of the All American Pipeline Acquisition are included in the Company's Consolidated Financial Statements effective July 30, 1998. See Note 9 to the accompanying Consolidated Financial Statements for pro forma information giving effect to the All American Pipeline Acquisition as if such transaction occurred on January 1, 1997. The Company's 1998 earnings were adversely affected by low crude oil prices throughout 1998. The NYMEX Crude Oil Price averaged $14.43 per barrel in 1998, approximately 30% and 34% below the 1997 and 1996 average NYMEX Crude Oil Price, respectively. Almost all of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The benchmark NYMEX Crude Oil Price at December 31, 1998, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $12.05 per barrel. Such price was the lowest year-end price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. Under full-cost accounting rules as prescribed by the SEC, unamortized costs of proved oil and natural gas properties are subject to a ceiling, which limits such costs to the Standardized Measure. At December 31, 1998, the capitalized costs of the Company's proved oil and natural gas properties exceeded the Standardized Measure, and the Company recorded a non-cash, after-tax charge to expense of $109.0 million ($173.9 million pre-tax). Such amount was partially offset by a $37.1 million after-tax gain associated with the initial public offering of PAA. As of March 25, 1999, crude oil prices have recovered to such levels that would have resulted in a significantly lower writedown. Results of Operations Excluding the non-cash full cost ceiling writedown and the partnership- related gain, the Company reported net income for 1998 of $8.4 million, or $0.22 per share ($0.20 per share diluted), on total revenue of $1.2 billion, as compared to net income in 1997 of $14.3 million or $0.85 per share ($0.77 per share diluted), on total revenue of $862.2 million. Including the impact of the writedown and partnership-related gain, the Company reported a net loss of $58.6 million, or $3.77 per share in 1998. Net income for 1996 was $16.5 million, or $1.01 per share ($.94 per share diluted). Net income for 1996 included an $11.0 million benefit associated with the recognition of a portion of a deferred tax asset that was previously fully reserved and a $5.1 million extraordinary charge net of taxes for early extinguishment of debt. EBITDA increased 17% in 1998 to $80.3 million from the $68.4 million reported in 1997 and 40% from the $57.2 million reported in 1996. Cash flow from operations (cash provided by operating activities after minority interest but before 36 changes in assets and liabilities) was $42.0 million, $46.2 million and $39.9 million in 1998, 1997 and 1996, respectively. Net cash provided by operating activities was $37.6 million for the year ended December 31, 1998, as compared to $30.3 million for 1997 and $39.0 million in 1996. The decrease in 1997 from 1996 is attributable to the purchase of crude oil inventory in contango market transactions. Such inventory was hedged against price risk and was sold during the first quarter of 1998. Upstream Results The following table sets forth certain operating information of the Company for the periods presented:
Years Ended December 31, ---------------------------------------- 1998 1997 1996 ---------- ---------- ---------- (in thousands, except per unit data) Average Daily Production Volumes Barrels of oil equivalent California (approximately 90% oil) 13.8 11.2 9.2 Sunniland Trend (100% oil) 4.8 5.3 4.7 Illinois Basin (100% oil) 3.5 3.6 3.5 Sold properties - 0.1 0.1 ---------- ---------- ---------- Total (approximately 94% oil) 22.1 20.2 17.5 ========== ========== ========== Unit Economics Average sales price per BOE $ 12.73 $ 14.83 $ 15.22 Production expense per BOE 6.29 6.16 6.04 ---------- ---------- ---------- Gross margin per BOE 6.44 8.67 9.18 Upstream G&A expense per BOE 0.68 0.65 0.74 ---------- ---------- ---------- Gross profits per BOE $ 5.76 $ 8.02 $ 8.44 ---------- ---------- ----------
Oil and natural gas production volumes in 1998 totaled 8.1 million BOE, a 9% increase over the 1997 level of 7.4 million BOE and 26% above the 1996 level of 6.4 million BOE. The volume increase in 1998 is primarily associated with the continued exploitation and expansion of the Company's California properties, offset somewhat by shut-ins and declines in production from certain of its other properties. During the second half of 1998, the Company shut-in certain of its lower margin wells in California, Florida and Illinois due to low crude oil prices, resulting in a decrease in average net daily production of approximately 1,120 BOE per day. Average net daily production from the Company's California Properties increased to approximately 13,800 BOE per day in 1998, up 2,600 BOE per day, or 23% over 1997 and 50% over the 1996 level. Excluding production from the Arroyo Grande Field which was acquired during the fourth quarter of 1997, California production and aggregate Company production were up 13% and 4%, respectively, from 1997. Net production from the Company's Sunniland Trend properties averaged approximately 4,800 barrels of oil per day in 1998, compared to 5,300 barrels per day in 1997 and 4,700 barrels per day in 1996. Due to the high volume of production that is generated by very few wells in the Sunniland Trend, abrupt or abnormal declines or downtime due to mechanical, marketing, or other conditions on any of the properties in this area could have a significant impact on production. Net daily production in the Illinois Basin averaged approximately 3,500 barrels per day during 1998, 3,600 barrels per day in 1997 and 3,500 barrels per day in 1996. Oil and natural gas revenues were $102.8 million in 1998, a decrease of 6% from the 1997 comparative period due to decreased product prices which offset increased production volumes. Oil and natural gas revenues increased to $109.4 million in 1997 as compared to $97.6 million in 1996 due to increased production volumes. The Company's average product price, which represents a combination of fixed and floating price sales arrangements and incorporates location and quality discounts from the benchmark NYMEX prices, averaged $12.73 per BOE in 1998, 14% and 16% lower than the price received in 1997 and 1996, respectively. The NYMEX Crude Oil Price averaged $14.43 per barrel in 1998, $20.63 per barrel in 1997, and $21.99 per barrel in 1996. Financial swap arrangements and futures transactions entered into by the Company to hedge production are included in the Company's average product prices. Such transactions had the effect of increasing the overall average price per BOE received by the Company by $2.98 in 1998 and decreasing such price by $1.26 in 1997 and $2.62 in 1996. Approximately 59% of the Company's crude oil production was hedged throughout 1998 at an average NYMEX Crude Oil Price of approximately $19.80 per barrel. The Company routinely hedges a portion of its crude oil production. See "-- Capital Resources, Liquidity and Financial Condition -- Changing Oil and Natural Gas Prices" and "Item 7a, -- Quantitative and Qualitative Disclosures about Market Risk". 37 Upstream unit gross margin (well-head revenue less production expenses) for 1998 was $6.44 per BOE, compared to $8.67 per BOE in 1997 and $9.18 per BOE in 1996. Average unit production expenses were $6.29 per BOE, $6.16 per BOE and $6.04 per BOE in 1998, 1997, and 1996, respectively. Total production expenses increased to $50.8 million from $45.5 million and $38.7 million in 1997 and 1996, respectively, primarily due to increased production volumes resulting from the Company's acquisition and exploitation activities. Unit G&A expense increased slightly to $0.68 per BOE in 1998 compared to $0.65 per BOE during 1997 and $0.74 per BOE during 1996. Total upstream G&A expense was $5.5 million, $4.8 million and $4.8 million in 1998, 1997 and 1996, respectively. The increase in 1998 is primarily associated with the Company's California upstream acquisitions. Upstream depreciation, depletion and amortization ("DD&A") per BOE excluding the writedown was $3.00, $2.83 and $3.00 per BOE in 1998, 1997 and 1996, respectively. Total upstream DD&A expense, likewise excluding the writedown, was $24.2 million, $20.9 million and $19.2 million in 1998, 1997 and 1996, respectively. Midstream Results The following table sets forth certain midstream operating information of the Company for the periods presented. Year Ended December 31, ---------------------------------- 1998 1997 1996 ------- -------- -------- (in thousands) Operating Results: Gross margin Pipeline transportation service $ 16,490 $ - $ - Terminalling and storage and gathering and marketing 21,871 12,480 9,531 -------- -------- -------- Total 38,361 12,480 9,531 General and administrative expense (5,297) (3,529) (2,974) -------- -------- -------- Gross profit $ 33,064 $ 8,951 $ 6,557 ======== ======== ======== Average Daily Volumes (barrels) Pipeline tariff activities 113 - - Pipeline margin activities 50 - - -------- -------- -------- Total 163 - - ======== ======== ======== Lease gathering 88 71 59 Bulk purchases 95 49 32 Terminal throughput 80 77 59 Pipeline Operations. The activities from pipeline operations generally consist of transporting third-party volumes of crude oil for a tariff ("Tariff Activities") and merchant activities designed to capture price differentials between the cost to purchase and transport crude oil to a sales point and the price received for such crude oil at the sales point ("Margin Activities"). Tariffs on the All American Pipeline vary by receipt point and delivery point. Tariffs for OCS crude oil delivered to California markets averaged $1.41 per barrel and tariffs for OCS volumes delivered to West Texas averaged $2.96 per barrel as of December 31, 1998. Tariffs for San Joaquin Valley crude oil delivered to West Texas averaged $1.25 per barrel as of December 31, 1998. 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. As is common with most merchant activities, the ability of the Company to generate a profit on 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 it sells crude oil. The Company combines reporting of gross margin for Tariff Activities and Margin Activities due to the sharing of fixed costs between the two activities. As noted above, the results of operations of the Company include approximately five months of operations of the All American Pipeline and the SJV Gathering System which were acquired effective July 30, 1998. Tariff revenues for this period were $19.0 million and are primarily attributable to transport volumes from the Santa Ynez field (approximately 65,300 barrels per day) and the Point Arguello field (approximately 24,300 barrels per day). The margin between revenue and direct cost of crude purchased was approximately $3.9 million. Operations and maintenance expenses were $6.1 million. 38 The following table sets forth All American Pipeline average deliveries per day within and outside California from July 30, 1998, through December 31, 1998 (in thousands). Deliveries: Average daily volumes (barrels): Within California 111 Outside California 52 ------ Total 163 ====== Terminalling and Storage Activities and Gathering and Marketing Activities. Gross margin from terminalling and storage and gathering and marketing activities was $21.9 million for the year ended December 31, 1998, reflecting a 75% increase over the $12.5 million reported for the 1997 period and an approximate 129% increase over the $9.5 million reported for 1996. Gross profit totaled $17.5 million for 1998, approximately 96% and 167% over the amounts reported for 1997 and 1996, respectively. Net of interest expense associated with contango inventory transactions, gross margin and gross profit for 1998 were $21.1 million and $16.8 million, respectively, representing increases of approximately 82% and 108% over the 1997 respective amounts. The Company did not have any material contango inventory transactions in 1996. The increase in gross margin was primarily attributable to an increase in the volumes gathered and marketed in West Texas, Louisiana and the Gulf of Mexico and activities at the Cushing Terminal. Total G&A expenses were $5.3 million for the year ended December 31, 1998, compared to $3.5 million and $3.0 million for 1997 and 1996, respectively. Such increases were primarily attributable to increased personnel as a result of the continued expansion of the Company's terminalling and storage activities and gathering and marketing activities as well as G&A expenses associated with the addition of the All American Pipeline and the SJV Gathering System. Depreciation and amortization was $5.4 million in 1998, as compared to $1.2 million in 1997 and $1.1 million in 1996. The increase is due to the acquisition of the All American Pipeline and the SJV Gathering System in 1998. General Total G&A expenses, including midstream activities, were $10.8 million for the year ended December 31, 1998, compared to $8.3 million and $7.7 million for 1997 and 1996, respectively. The increases are primarily attributable to increased expenses associated with the Company's midstream activities, including the July 1998 All American Pipeline Acquisition and the Company's upstream California acquisitions. Primarily as a result of the All American Pipeline Acquisition and increased production levels, total DD&A for the year ended December 31, 1998, was $31.0 million as compared to $23.8 million and $21.9 million in 1997 and 1996, respectively. Interest expense, net of capitalized interest, for 1998 increased to $35.7 million as compared to $22.0 million in 1997 and $17.3 million in 1996. The increases are primarily due to the debt incurred for the All American Pipeline Acquisition and to higher debt levels related to the Company's acquisition, exploitation, development and exploration activities. During 1998, 1997 and 1996, the Company capitalized $3.7 million, $3.3 million and $3.6 million of interest, respectively. During 1998, the Company recognized a pre-tax gain (net of approximately $9.2 million in formation related expenses) in connection with the formation of PAA. Such gain is the result of an increase in the book value of the Company's equity in PAA to reflect their proportionate share of the underlying net assets of PAA due to the sale of units in the IPO. 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. During 1996, the Company settled two lawsuits filed in 1992 and 1993 against certain of its officers and directors for a cash payment of approximately $6.3 million which resulted in a charge to 1996 first quarter earnings of $4 million. Approximately $4.1 million of such amount was paid by the Company's insurance carrier and $2.2 million was paid by the Company. For the year ended December 31, 1998, the Company recognized a deferred tax benefit of $43.6 million and a current tax provision of $0.9 million. For the year ended December 31, 1997, the Company recognized a deferred tax provision of $8.0 million and a current tax provision of $0.4 million. For 1996, the Company recognized a net deferred tax benefit before extraordinary item of $3.9 million. Such amount consists of a $7.1 million deferred tax provision on the Company's income before extraordinary item and an $11.0 million reduction in the valuation allowance reserved against the Company's net deferred tax asset. In 1996, the Company also reported a $3.4 million deferred tax benefit as an extraordinary item which was attributable 39 to the $8.5 million pre-tax first quarter extraordinary loss from the early redemption of the Company's 12% Senior Subordinated Notes. At December 31, 1998, the Company has a net deferred tax asset of $47.8 million. Management believes that it is more likely than not that it will generate taxable income sufficient to realize such asset based on certain tax planning strategies available to the Company. As an example, the Company, through its existing ownership in PAA which is publicly traded, could generate sufficient taxable income to utilize the tax asset existing at December 31, 1998. Therefore, the Company has concluded that the valuation allowance is adequate. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133"). FAS 133 is effective for all fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. For fair value hedge transactions in which the Company is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash flow hedge transactions, in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The Company has not yet determined the affect that the adoption of FAS 133 will have on its results of operations or financial position. In November 1998, the Emerging Issues Task Force ("EITF") released Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF 98-10 deals with entities that enter into derivatives and other third-party contracts for the purchase and sale of a commodity in which they normally do business (for example, crude oil and natural gas). The EITF reached a consensus that energy trading contracts should be measured at fair value determined as of the balance sheet date with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The EITF acknowledged that determining whether or when an entity is involved in energy trading activities is a matter of judgment that depends on the relevant facts and circumstances. As such, certain factors or indicators have been identified by the EITF which should be considered in evaluating whether an operation's energy contracts are entered into for trading purposes. EITF 98-10 is required to be applied to financial statements issued by the Company beginning in 1999. The adoption of this consensus is not expected to have a material impact on the Company's results of operations or financial position. Capital Resources, Liquidity and Financial Condition All American Pipeline Acquisition On July 30, 1998, PAAI, a wholly owned unrestricted subsidiary of the Company, as defined in the indentures for the Company's $200 million 10.25% Senior Subordinated Notes (the "Indentures"), acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot Ventures Seven, Inc., a wholly-owned subsidiary of Goodyear for approximately $400 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline System, a 1,233-mile crude oil pipeline extending from California to Texas, and a 45-mile crude oil gathering system in the San Joaquin Valley of California, as well as other assets related to such operations. Financing for the acquisition was provided through (i) PAAI's $325 million, limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston, N.A. and other lenders (the "PAAI Credit Facility") and (ii) an approximate $114 million capital contribution to PAAI by the Company. Approximately $29 million of such capital contribution was funded from existing cash and the Company's revolving credit facility (the "Revolving Credit Facility") and the remaining $85 million was provided by a privately placed issuance of the Company's Series E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock"). A portion of the PAAI Credit Facility was subsequently repaid and the remainder restructured as described below. On July 29, 1998, the Company sold in a private placement 170,000 shares of its Series E Preferred Stock for $85 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 the Company's option and 40 are cumulative from the date of issue. Each share of Series E Preferred Stock is convertible into 27.78 shares of the Company's common stock ("Common Stock") (an initial effective conversion price of $18.00 per share) and in certain circumstances may be converted at the Company's 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 the option of the Company after March 31, 1999, at 110% of stated value and at declining amounts thereafter. If not previously redeemed or converted, the Series E Preferred Stock is required to be redeemed in 2012. Formation and Initial Public Offering of PAA and Related Financial Restructuring PAA was formed during 1998 to acquire and operate the midstream crude oil business and assets of the Plains Midstream Subsidiaries, including the All American Pipeline and SJV Gathering System. PAAI is the general partner of the Partnership. On November 23, 1998, PAA sold 13,085,000 common units representing limited partner interests in PAA and received net proceeds therefrom of approximately $244.7 million. PAAI is both the sole general partner of PAA and the majority owner, holding a 57% interest through ownership of approximately 17 million common and subordinated units and its general partner interest. For financial statement purposes, the assets, liabilities and earnings of PAA are included in the Company's consolidated financial statements with the public Unitholders' 43% ownership reflected as a minority interest. Concurrently with the closing of the IPO, the Company and PAA reduced consolidated indebtedness by approximately $240 million and significantly restructured or eliminated various midstream credit facilities. Concurrently with the closing of the IPO, PAA entered into the Bank Credit Agreement that includes the Term Loan Facility and the PAA Revolving Credit Facility. PAA may borrow up to $50 million under the PAA Revolving Credit Facility for acquisitions, capital improvements, working capital and general business purposes. The Term Loan Facility bears interest at PAA's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. Borrowings under the PAA Revolving Credit Facility bear interest at PAA's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the PAA Revolving Credit Facility and, with respect to each issued letter of credit, an issuance fee. At December 31, 1998, $175 million was outstanding under the Term Loan Facility, which amount represents indebtedness assumed from the General Partner. PAA has two 10-year interest rate swaps (subject to cancellation by the counter party after seven years) aggregating $175 million notional principal amount, which fix the LIBOR portion of the interest rate (not including the applicable margin) at a weighted average rate of approximately 5.24%. The Term Loan Facility matures in 2005, and no principal is scheduled for payment prior to maturity. The Term Loan Facility may be prepaid at any time without penalty. The PAA Revolving Credit Facility expires in 2000. All borrowings for working capital purposes outstanding under the PAA Revolving Credit Facility must be reduced to no more than $8 million for at least 15 consecutive days during each fiscal year. At December 31, 1998, there were no amounts outstanding under the PAA Revolving Credit Facility. The Bank Credit Agreement is secured by a lien on substantially all of the assets of PAA. Simultaneously with the IPO, PAA entered into a $175 million letter of credit and borrowing facility, which replaced an existing facility. The purpose of the Letter of Credit Facility is to provide (i) standby letters of credit to support the purchase and exchange of crude oil for resale and (ii) borrowings to finance crude oil inventory which have been hedged against future price risk or designated as working inventory. The Letter of Credit Facility is collateralized by a lien on substantially all of the assets of PAA. Aggregate availability under the Letter of Credit Facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain current assets and current liabilities of PAA, primarily crude oil inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil. At December 31, 1998, the borrowing base under the Letter of Credit Facility was approximately $175 million. The Letter of Credit Facility has a $40 million sublimit for borrowings to finance crude oil purchased in connection with operations at PAA's crude oil terminal and storage facilities. All purchases of crude oil inventory financed are required to be hedged against future price risk on terms acceptable to the lenders. At December 31, 1998, approximately $9.8 million was outstanding under the sublimit. Letters of credit under the Letter of Credit Facility are generally issued for up to 70 day periods. Borrowings bear interest at PAA's option at either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable margin. PAA incurs a commitment fee on the unused portion of the borrowing sublimit under the Letter of Credit Facility and an issuance fee 41 for each letter of credit issued. The Letter of Credit Facility expires July 31, 2001. At December 31, 1998, there were outstanding letters of credit of approximately $62 million issued under the Letter of Credit Facility. Both the Letter of Credit Facility and the Bank Credit Agreement contain a prohibition on distributions on, or purchases or redemptions of, Units if any Default or Event of Default (as defined) is continuing. In addition, both facilities contain various covenants limiting the ability of PAA to (i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) engage in transactions with affiliates, (v) make investments, (vi) enter into hedging contracts and (vii) enter into a merger, consolidation or sale of its assets. In addition, the terms of the Letter of Credit Facility and the Bank Credit Agreement require PAA to maintain (i) a Current Ratio (as defined) of at least 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control (as defined) of the Company constitutes an Event of Default. PAA will distribute 100% of its Available Cash within 45 days after the end of each quarter to Unitholders of record and to the General Partner. Available Cash is generally defined as all cash and cash equivalents of PAA on hand at the end of each quarter less reserves established by the General Partner for future requirements. Distributions of Available Cash to holders of Subordinated Units are subject to the prior rights of holders of Common Units to receive the minimum quarterly distribution ("MQD") for each quarter during the subordination period (which will not end earlier than December 31, 2003) and to receive any arrearages in the distribution of the MQD on the Common Units for the prior quarters during the subordination period. The MQD is $0.45 per unit ($1.80 per unit on an annual basis). Approximately 10 million of the 17 million Units held by PAAI are Subordinated Units. Upon expiration of the Subordination Period, all Subordinated Units will be converted on a one-for-one basis into Common Units and will participate pro rata with all other Common Units in future distributions of Available Cash. Under certain circumstances, up to 50% of the Subordinated Units may convert into Common Units prior to the expiration of the Subordination Period. Common Units will not accrue arrearages with respect to distributions for any quarter after the Subordination Period and Subordinated Units will not accrue any arrearages with respect to distributions for any quarter. If quarterly distributions of Available Cash exceed the MQD or the Target Distribution Levels (as defined), the General Partner will receive distributions which are generally equal to 15%, then 25% and then 50% of the distributions of Available Cash that exceed the MQD or Target Distribution Level. The Target Distribution Levels are based on the amounts of Available Cash from PAA's Operating Surplus (as defined) distributed with respect to a given quarter that exceed distributions made with respect to the MQD and Common Unit arrearages, if any. On February 12, 1999, PAA paid a cash distribution of $0.193 per unit on its outstanding Common Units and Subordinated Units. The $5.8 million distribution was paid to all Unitholders of record at the close of business on January 29, 1999. A distribution of approximately $118,000 was paid to PAAI as general partner and $3.3 million as limited partner with the remainder being distributed to PAA's public Unitholders. The distributions represented a partial quarterly distribution for the 39-day period from November 23, 1998, the closing of the IPO, through December 31, 1998. Revolving Credit Facility The Company has a $225 million revolving credit facility (the "Revolving Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit Facility is guaranteed by all of the Company's upstream subsidiaries and is secured by the upstream oil and gas properties of the Company and the guaranteeing subsidiaries and the stock of such subsidiaries. The borrowing base under the Revolving Credit Facility is subject to borrowing base availability as determined from time to time by the Lenders in good faith, in the exercise of the Lenders' sole discretion, and in accordance with customary practices and standards in effect from time to time for oil and natural gas loans to borrowers similar to the Company. Such borrowing base may be affected from time to time by the performance of the Company's oil and natural gas properties and changes in oil and natural gas prices. The borrowing base was affirmed at $225 million in December 1998. The next redetermination will be in the second quarter of 1999. The Company incurs a commitment fee of 3/8% per annum on the unused portion of the borrowing base. The Revolving Credit Facility, as amended, matures on July 1, 2000, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing October 1, 2000, with a final maturity of July 1, 2005. The Revolving Credit Facility bears interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 1998, outstanding borrowings under the Revolving Credit Facility were $52 million. 42 Capital Expenditures At December 31, 1998, the Company had a working capital deficit of approximately $13.9 million. The Company has historically operated with a working capital deficit due primarily to ongoing capital expenditures that have been financed through cash flow and the Revolving Credit Facility. The working capital deficits at December 31, 1997 and 1996, were $6.0 million and $4.8 million, respectively. The Company has made and will continue to make, substantial capital expenditures for the acquisition, exploitation, development, exploration and production of oil and natural gas reserves. Historically, the Company has financed these expenditures primarily with cash generated by operations, bank borrowings and the sale of subordinated notes, common stock and preferred stock. The Company intends to make aggregate capital expenditures of approximately $76 million in 1999, including approximately $64 million on the development and exploitation of its California, Sunniland Trend and Illinois Basin properties, approximately $3 million on exploration activities primarily in the Sunniland Trend, approximately $8.8 million for midstream activities, primarily related to the expansion of the Cushing Terminal, and approximately $0.6 million for other equipment. In addition, the Company intends to continue to pursue the acquisition of underdeveloped producing properties. The Company believes that it will have sufficient cash from operating activities and borrowings under the Revolving Credit Facility to fund such planned capital expenditures. The midstream capital expenditures are expected to be funded by PAA through working capital, cash flow and draws under the PAA Revolving Credit Facility. Changing Oil and Natural Gas Prices The Company's upstream activities are affected by changes in crude oil prices which have historically been volatile. Although the Company has routinely hedged a substantial portion of its crude oil production and intends to continue this practice, substantial future crude oil price declines would adversely affect the Company's overall results, and therefore its liquidity. Furthermore, low crude oil prices could affect the Company's ability to raise capital on terms favorable to the Company. In order to manage its exposure to commodity price risk, the Company has routinely hedged a portion of its crude oil production. For 1999, the Company has entered into crude oil swap agreements which provide the Company with downside price protection on approximately 9,000 barrels of oil per day at a NYMEX Crude Oil Price of approximately $18.25 per barrel. Thus, based on the Company's average fourth quarter 1998 crude oil production rate, these arrangements generally provide the Company with downside price protection for approximately 45% of its production. In addition, the Company has fixed price arrangements on 2,000 barrels per day in 2000 at a NYMEX Crude Oil Price of $15.30 per barrel, or approximately 10% of fourth quarter 1998 crude oil production levels. The foregoing NYMEX Crude Oil Prices are before quality and location differentials. Management intends to continue to maintain hedging arrangements for a significant portion of its production. Such contracts may expose the Company to the risk of financial loss in certain circumstances. See "Item 1, Business -- Product Markets and Major Customers" and "Item 7a, -- Quantitative and Qualitative Disclosures About Market Risk". Additionally, decreases in the prices of oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Almost all of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The benchmark NYMEX Crude Oil Price at December 31, 1998, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $12.05 per barrel. Such price was the lowest year-end price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. Under full-cost accounting rules as prescribed by the SEC, unamortized costs of proved oil and natural gas properties are subject to a ceiling, which limits such costs to the Standardized Measure. At December 31, 1998, the capitalized costs of the Company's proved oil and natural gas properties exceeded the Standardized Measure, and the Company recorded a non-cash, after-tax charge to expense of $109.0 million ($173.9 million pre-tax). As is common with most merchant activities, the ability of the Company to generate a profit on its 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 it sells 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. Investing Activities Net cash flows used in investing activities were $483.4 million, $107.6 million and $52.5 million for the years ended December 31, 1998, 1997 and 1996, respectively. Included in such amounts are payments, net of cash received from property 43 sales and reimbursements from partners, for acquisition, development and exploration costs of $80.2 million, $103.0 million and $49.9 million for the same periods, respectively. Approximately $394.0 million and $4.2 million related to the All American Pipeline Acquisition and the Cushing Terminal expansion, respectively, are included in investing activities for 1998. Such payments for 1997 include $22.0 million related to the acquisition of the Montebello Field. The Company expended $1.1 million, $4.7 million and $2.6 million in 1998, 1997 and 1996, respectively, for other property additions, primarily for surface fee land acquired in connection with the Montebello Field in 1997, midstream activities and computer equipment. Financing Activities Net cash provided by financing activities amounted to $448.6 million, $78.5 million and $9.9 million for 1998, 1997 and 1996, respectively. Aggregate proceeds from long-term borrowings for these same years were $570.6 million, $266.9 million and $263.7 million, respectively, while payments of long-term debt were $423.6 million, $207.0 million and $248.1 million for the respective periods. Financing activities for 1998 include the following related to the All American Acquisition: (i) approximately $300 million in borrowings and $15 million in repayments under the PAAI Credit Facility; (ii) proceeds of $85 million from the issuance of the Series E Preferred Stock; (iii) approximately $16 million in borrowings under the Revolving Credit Facility to fund the Company's capital contribution to PAAI and (iv) approximately $6.1 million of financing costs. Financing activities for 1998 related to the PAA IPO include (i) approximately $242.1 million in net proceeds; (ii) approximately $117 million in repayments on the PAAI Credit Facility; (iii) approximately $123.6 million of repayments on the Revolving Credit Facility and (iv) approximately $9.9 million of financing costs. Approximately $25 million borrowed under the Revolving Credit Facility to fund the acquisition of the Montebello Field and related surface fee land is included in proceeds from long-term debt in 1997. Also included in financing activities during 1997 are net proceeds of approximately $53 million from the sale of the Company's Series C & D 10.25% Notes and a corresponding payment on the Revolving Credit Facility. Financing activities during 1996 include net proceeds of approximately $144.6 million from the Company's Series A & B 10.25% Notes, approximately $107 million for the repayment of the Company's 12% Notes, including the 6% call premium and the net defeasance costs, and approximately $42 million for the repayment of the Illinois Basin acquisition bridge indebtedness. Remaining long-term debt activity is primarily related to advances received and payments made on the Revolving Credit Facility. Financing activities during 1998 and 1997 include proceeds of $32 and $39 million, respectively, from short-term borrowings and $40 and $21 million, respectively, of repayments related to crude oil inventory transactions at the Cushing Terminal. Financing activities include proceeds from the sale of capital stock of $0.8 million, $1.1 million and $1.8 million in 1998, 1997 and 1996, respectively. Such proceeds were primarily from the exercise of employee stock options. Commitments Although the Company obtained environmental studies on its properties in California, the Sunniland Trend and Illinois Basin, and the Company believes 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. Consistent with normal industry practices, substantially all of the Company's 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. The Company has estimated that the costs to perform these tasks is approximately $12.8 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 1998, 1997 and 1996 include $0.8 million, $0.6 million and $0.8 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected 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. PAA owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's linefill requirements. PAA amended its tariff with the FERC to require third party shippers to buy linefill from PAA and replenish the linefill when their movement of crude oil on the All American Pipeline System is completed. Accordingly, PAA does not anticipate large variations in the amounts of linefill provided by PAA in the future. Year 2000 Year 2000 Issue. Some software applications, hardware and equipment and embedded chip systems identify dates using only the last two digits of the year. These products may be unable to distinguish between dates in the Year 2000 and dates in the 44 year 1900. That inability (referred to as the "Year 2000" issue), if not addressed, could cause applications, equipment or systems to fail or provide incorrect information after December 31, 1999, or when using dates after December 31, 1999. This in turn could have an adverse effect on the Company, because the Company directly depends on its own applications, equipment and systems and indirectly depends on those of other entities with which the Company must interact. Compliance Program. In order to address the Year 2000 issues, the Company has implemented a Year 2000 project for all of its business units. A project team has been established to coordinate the six phases of this Year 2000 project to assure that key automated systems and related processes will remain functional through Year 2000. Those phases include: (i) awareness, (ii) assessment, (iii) remediation, (iv) testing, (v) implementation of the necessary modifications and (vi) contingency planning. The key automated systems consist of (a) financial systems applications, (b) hardware and equipment, (c) embedded chip systems and (d) third-party developed software. The evaluation of the Year 2000 issue includes the evaluation of the Year 2000 exposure of third parties material to the operations of the Company or any of its business units. The Company retained a Year 2000 consulting firm to review the operations of all of its business units and to assess the impact of the Year 2000 issue on such operations. Such review has been completed and the consultant's recommendations are being utilized in the Year 2000 project. The Company's State of Readiness. The awareness phase of the Year 2000 project has begun with a corporate-wide awareness program which will continue to be updated throughout the life of the project. The portion of the assessment phase related to financial systems applications has been substantially completed and the necessary modifications and conversions are underway. The portion of the assessment phase which will determine the nature and impact of the Year 2000 issue for hardware and equipment, embedded chip systems, and third-party developed software is continuing. The Company has retained a Year 2000 consulting firm which is currently identifying and evaluating field equipment which has embedded chip systems. The assessment phase of the project involves, among other things, efforts to obtain representations and assurances from third parties, including third party vendors, that their hardware and equipment, embedded chip systems, and software being used by or impacting the Company or any of its business units are or will be modified to be Year 2000 compliant. To date, the responses from such third parties are inconclusive. As a result, management cannot predict the potential consequences if these or other third parties are not Year 2000 compliant. The exposure associated with the Company's interaction with third parties is currently being evaluated. Management expects that the remediation, testing and implementation phases will be substantially completed by the third quarter of 1999. Contingency Planning. As part of the Year 2000 project, the Company will seek to determine which of its business activities may be vulnerable to a Year 2000 disruption. Appropriate contingency plans will then be developed for each "at risk" business activity to provide an alternative means of functioning which minimizes the effect of the potential Year 2000 disruption, both internally and on those with whom it does business. Such contingency plans are expected to be completed by the fourth quarter of 1999. Costs to Address Year 2000 Compliance Issues. Through December 31, 1998, the Company has expended approximately $380,000 in its Year 2000 project, excluding costs borne by PAA. While the total cost to the Company of the Year 2000 project is still being evaluated, the Company currently estimates that the costs to be incurred in 1999 and 2000 associated with assessing, testing, modifying or replacing financial system applications, hardware and equipment, embedded chip systems and third party developed software is between $350,000 and $450,000. The Company expects to fund these expenditures with cash from operations or borrowings. Based upon these estimates, the Company does not expect the costs of its Year 2000 project to have a material adverse effect on its financial position, results of operation or cash flows. Risk of Non-Compliance. The major applications that pose the greatest Year 2000 risks for the Company if implementation of the Year 2000 compliance program is not successful are the Company's financial systems applications and the Company's SCADA computer systems and embedded chip systems in field equipment. The potential problems if the Year 2000 compliance program is not successful are disruptions of the Company's revenue gathering from and distribution to its customers and vendors and the inability to perform its other financial and accounting functions. Failures of embedded chip systems in field equipment of the Company or its customers could disrupt the Company's upstream exploitation, development, production and exploration activities and its midstream crude oil transportation, terminalling and storage activities and gathering and marketing activities. While the Company believes that its Year 2000 project will substantially reduce the risks associated with the Year 2000 issue, there can be no assurance that it will be successful in completing each and every aspect of the project on schedule, and if successful, the project will have the expected results. Due to the general uncertainity inherent in the Year 2000 issues, the 45 Company cannot conclude that its failure or the failure of third parties to achieve Year 2000 compliance will not adversely affect its financial position, results of operations or cash flows. Item 7a QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS The Company is exposed to various market risks, including volatility in crude oil and natural gas commodity prices and interest rates. To manage such exposure, the Company enters into various derivative transactions. The Company does not enter into derivative transactions for speculative trading purposes. Substantially all the Company's derivative contracts are exchange traded or with major financial institutions and the risk of credit loss is considered remote. In its upstream activities, in order to manage its exposure to commodity price risk, the Company routinely hedges a portion of its crude oil production. For 1999, the Company has entered into crude oil swap agreements that provide the Company with downside price protection on approximately 9,000 barrels of oil per day at a NYMEX Crude Oil Price of approximately $18.25 per barrel. Thus, based on the Company's average fourth quarter 1998 crude oil production rate, these arrangements provide the Company with downside price protection for approximately 45% of its crude oil production throughout 1999. Subsequent to December 31, 1998, the Company entered into additional arrangements which fix the price on 2,000 barrels per day in 2000 at a NYMEX Crude Oil Price of $15.30 per barrel, or approximately 10% of fourth quarter 1998 crude oil production levels. While these hedging arrangements reduce the Company's exposure to decreases in crude oil prices, they may also limit the benefit the Company might otherwise receive from crude oil price increases In its midstream activities, as the Company purchases crude oil, it establishes 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, the Company seeks to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. From time to time, the Company enters into fixed price delivery contracts, floating price collar arrangements, financial swaps and oil futures contracts as hedging devices. To ensure a fixed price for future production, the Company may sell a futures contract and thereafter either (i) make physical delivery of its product to comply with such contract or (ii) buy a matching futures contract to unwind its futures position and sell its production to a customer. Such contracts may expose the Company to the risk of financial loss in certain circumstances, including instances where production is less than expected, the Company's customers fail to purchase or deliver the contracted quantities of crude oil , or a sudden, unexpected event materially affects crude oil prices. Such contracts may also restrict the ability of the Company to benefit from unexpected increases in crude oil prices. The Company's policy is generally to purchase only crude oil for which it has a market and to structure its sales contracts so that crude oil price fluctuations do not materially affect the gross margin which it receives. The Company does 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 the Company to indeterminable losses. The Company has interest rate swaps on an aggregate $200 million notional principal amount, which fix the LIBOR portion of the interest rate (not including the applicable margin) on the Term Loan Facility and a portion of the Revolving Credit Facility. At December 31, 1998, the Company would be required to pay approximately $3.3 million to terminate the interest rate swaps. 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: Change in Fair Fair Value from 10% At December 31, 1998 Value Adverse Price Change -------------------- ------ -------------------- (in millions) Crude Oil Swaps $ 16.9 $ (4.3) Futures contracts 1.8 (0.3) 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 NYMEX market prices compared to the contract price of the swap and approximate the 46 gain 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 prices, the fair value of the Company's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. Interest Rate Risk The Company's debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal cash flows and the related weighted average interest rates by expected maturity dates. The Company's 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, 1998. 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, 1998.
December 31, ------------------------------------------------------------------------- Expected Year of Maturity ------------------------------------------------------------------------- Fair 1999 2000 2001 2002 2003 Thereafter Total Value -------- ------- ------- ------- ------- ---------- ------- --------- (dollars in millions) Liabilities: Short-term debt - variable rate $ 9.7 $ - $ - $ - $ - $ - $ 9.7 $ 9.7 Average interest rate 6.80% Long-term debt - variable rate - - - - - 175.0 175.0 175.0 Average interest rate - - - - - 6.75% Long-term debt - fixed rate - - - - - 200.0 200.0 202.0 Average interest rate - - - - - 10.25% Redeemable Preferred Stock - - - - - $ 88.5 88.5 88.5
Additional details regarding accounting policy for these financial instruments are set forth in Note 1 to the Consolidated Financial Statements. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required to be provided in this item is included in the Consolidated Financial Statements of the Company, including the Notes thereto, attached hereto as pages F-1 to F-30 and such information is incorporated herein by reference. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE There were no disagreements on accounting and financial disclosure with the Company's independent accountants. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information regarding the directors of the Company will be included in the proxy statement for the 1999 Annual Meeting of Stockholders (the "Proxy Statement") to be filed within 120 days after December 31, 1998, and is incorporated herein by reference. Information with respect to the Company's executive officers is presented in Part I, Item 4 of this Report. 47 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 Information, if any, regarding beneficial ownership of the Common Stock will be included in the Proxy Statement and is incorporated herein by reference. 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. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) (1) Financial Statements The financial statements filed as part of this report are listed in the "Index to Consolidated Financial Statements" on Page F-1 hereof. (2) Exhibits 2(a) 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(a) 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(b) 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(c) 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(d) Certificate of Designation, Preference and Rights of Series E Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed August 11, 1998). 4 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(a) 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(b) Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the Company's Form S-1 Registration Statement (Reg. No. 33-33986)). 4(c) 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(d) 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). 10(a)* 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). 48 10(b)* 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(c)* 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(d)* 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(e)* 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)). 10(f)* 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(g)* 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(h)* 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(i)* 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(j) 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(k) 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(l) 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(m) 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. 10(n) 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. 10(o)* Employment Agreement dated as of November 23, 1998, between Harry N. Pefanis and the Company. 21 Subsidiaries of the Company. 23(a) Consent of PricewaterhouseCoopers LLP. 27(b) Financial Data Schedule for the year ended December 31, 1998. *A management contract or compensation plan. (b) Reports on Form 8-K Amendment No. 2 to Current Report filed on December 7, 1998, on form 8-K/A which amends the following items, financial statements, exhibits or other portion of the Current Report on Form 8-K filed with the Securities and Exchange Commission on August 11, 1998, by the Company in connection with the acquisition by Plains All American Inc., a wholly-owned subsidiary of the Company, of three subsidiaries from Wingfoot Ventures Seven, Inc. A Current Report on Form 8-K filed December 7, 1998, with respect to the Company's transfer of its midstream assets to PAA and its operating partnerships, Plains Marketing, L.P. and All American Pipeline, L.P. by Plains All American Inc., a wholly owned subsidiary of the Company. This report also provided information on PAA's initial public offering of Common Units which closed on November 23, 1998. 49 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: March 31, 1999 By: /s/ Phillip D. Kramer -------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Date: March 31, 1999 By: /s/ Greg L. Armstrong -------------------------------------- Greg L. Armstrong, President and Chief Executive Officer (Principal Executive Officer) Date: March 31, 1999 By: /s/ Jerry L. Dees -------------------------------------- Jerry L. Dees, Director Date: March 31, 1999 By: /s/ Tom H. Delimitros -------------------------------------- Tom H. Delimitros, Director Date: March 31, 1999 By: /s/ Cynthia A. Feeback -------------------------------------- Cynthia A. Feeback, Assistant Treasurer, Controller and Principal Accounting Officer (Principal Accounting Officer) Date: March 31, 1999 By: /s/ William M. Hitchcock -------------------------------------- William M. Hitchcock, Director Date: March 31, 1999 By: /s/ Phillip D. Kramer -------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer) Date: March 31, 1999 By: /s/ Dan M. Krausse -------------------------------------- Dan M. Krausse, Chairman of the Board and Director 50 Date: March 31, 1999 By: /s/ John H. Lollar -------------------------------------- John H. Lollar, Director Date: March 31, 1999 By: /s/ Robert V. Sinnott -------------------------------------- Robert V. Sinnott, Director Date: March 31, 1999 By: /s/ J. Taft Symonds -------------------------------------- J. Taft Symonds, Director The Annual Report to Stockholders of the Company for the year ended December 31, 1998, and the proxy statement relating to the annual meeting of stockholders will be furnished to stockholders subsequent to the filing of this Annual Report on Form 10-K. Such documents have not been mailed to stockholders as of the date of this report. 51 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE ---- Plains Resources Inc. and Subsidiaries Consolidated Financial Statements: Report of Independent Accountants.................................................................F-2 Consolidated Balance Sheets as of December 31, 1998 and 1997......................................F-3 Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996........F-4 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996........F-5 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1998, 1997 and 1996..............................................................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 present fairly, in all material respects, the financial position of Plains Resources Inc. and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. 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 generally accepted auditing standards 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, 1999 F-2 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
December 31, ------------------------------ 1998 1997 ------------ ------------- ASSETS CURRENT ASSETS Cash and cash equivalents $ 6,544 $ 3,714 Accounts receivable 128,875 99,597 Inventory 42,520 22,802 Prepaid expenses and other 1,527 667 ----------- ------------ Total current assets 179,466 126,780 ----------- ------------ PROPERTY AND EQUIPMENT Oil and natural gas properties - full cost method Subject to amortization 596,203 498,038 Not subject to amortization 54,545 52,024 Crude oil pipeline, gathering and terminal assets 378,254 35,451 Other property and equipment 8,606 8,074 ----------- ------------ 1,037,608 593,587 Less allowance for depreciation, depletion and amortization (375,882) (180,279) ----------- ------------ 661,726 413,308 ----------- ------------ OTHER ASSETS 133,075 16,731 ----------- ------------ $ 974,267 $ 556,819 =========== ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and other current liabilities $ 170,985 $ 102,663 Interest payable 7,950 6,601 Royalties payable 4,211 5,016 Notes payable and other current obligations 10,261 18,511 ----------- ------------ Total current liabilities 193,407 132,791 BANK DEBT 52,000 80,000 BANK DEBT OF A SUBSIDIARY 175,000 - SUBORDINATED DEBT 202,427 202,661 OTHER LONG-TERM DEBT 2,556 3,067 OTHER LONG-TERM LIABILITIES 13,967 5,107 ----------- ------------ 639,357 423,626 ----------- ------------ COMMITMENTS AND CONTINGENCIES (NOTE 13) MINORITY INTEREST 173,461 - ----------- ------------ SERIES E CUMULATIVE CONVERTIBLE PREFERRED STOCK, STATED AT LIQUIDATION PREFERENCE 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 $1,354,000 and $2,629,000 at December 31, 1998 and 1997, respectively 21,946 20,671 Common Stock, $.10 par value, 50,000,000 shares authorized; issued and outstanding 16,881,938 and 16,703,074 shares at December 31, 1998 and 1997, respectively 1,688 1,670 Additional paid-in capital 124,679 122,887 Accumulated deficit (75,351) (12,035) ----------- ------------ 72,962 133,193 ----------- ------------ $ 974,267 $ 556,819 =========== ============
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, -------------------------------------------- 1998 1997 1996 ------------- ------------- ------------- REVENUES Oil and natural gas sales $ 102,754 $ 109,403 $ 97,601 Marketing, transportation, storage and terminalling revenues 1,129,689 752,522 531,698 Gain on formation of PAA (See Note 2) 60,815 - - Interest and other income 834 319 309 ------------- ------------- ------------- 1,294,092 862,244 629,608 ------------- ------------- ------------- EXPENSES Production expenses 50,827 45,486 38,735 Marketing, transportation, storage and terminalling expenses 1,091,328 740,042 522,167 General and administrative 10,778 8,340 7,729 Depreciation, depletion and amortization 31,020 23,778 21,937 Reduction in carrying cost of oil and natural gas properties 173,874 - - Interest expense 35,730 22,012 17,286 Litigation settlement - - 4,000 ------------- ------------- ------------- 1,393,557 839,658 611,854 ------------- ------------- ------------- Income (loss) before income taxes, extraordinary item and minority interest (99,465) 22,586 17,754 Minority interest 1,809 - - ------------- ------------- ------------- Income (loss) before income taxes and extraordinary item (101,274) 22,586 17,754 Income tax expense (benefit) Current 862 352 - Deferred (43,582) 7,975 (3,898) ------------- ------------- ------------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM (58,554) 14,259 21,652 EXTRAORDINARY ITEM: Loss on early extinguishment of debt, net of tax benefit - - (5,104) ------------- ------------- ------------- NET INCOME (LOSS) (58,554) 14,259 16,548 Less: cumulative preferred stock dividends 4,762 163 - ------------- ------------- ------------- NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (63,316) $ 14,096 $ 16,548 ============= ============= ============= Basic earnings per share: Income (loss) before extraordinary item $ (3.77) $ 0.85 $ 1.32 Extraordinary item - - (0.31) ------------- ------------- ------------- Net income (loss) $ (3.77) $ 0.85 $ 1.01 ============= ============= ============= Diluted earnings per share: Income (loss) before extraordinary item $ (3.77) $ 0.77 $ 1.23 Extraordinary item - - (0.29) ------------- ------------- ------------- Net income (loss) $ (3.77) $ 0.77 $ 0.94 ============= ============= =============
See notes to consolidated financial statements. F-4 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Year Ended December 31, ------------------------------------------ 1998 1997 1996 ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ (58,554) $ 14,259 $ 16,548 Items not affecting cash flows from operating activities: Depreciation, depletion and amortization 31,020 23,778 21,937 Reduction in carrying costs of oil and natural gas properties 173,874 - - Non-cash gain (See Note 2) (70,037) - - Minority interest in income 1,809 - - Loss on early extinguishment of debt, net of tax - - 5,104 Deferred income taxes (43,582) 7,975 (3,898) Other non-cash items 90 221 251 Change in assets and liabilities from operating activities: Accounts receivable 24,952 (9,518) (41,046) Inventory (19,057) (18,239) 551 Purchase of pipeline linefill (3,904) - - Prepaids and other (868) 128 (64) Accounts payable and other current liabilities 410 9,858 37,296 Interest payable 1,467 1,494 977 Royalties payable 10 351 1,352 ------------ ------------ ------------ Net cash provided by operating activities 37,630 30,307 39,008 ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Midstream acquisition (see Note 9): Payment for acquisition of pipeline and related assets (392,528) - - Payment for working capital (excluding cash received of $7,481) (1,498) - - Payment for crude oil pipeline, gathering and terminal assets (8,131) (923) (1,850) Cash received from the sale of oil and gas natural properties 131 2,667 3,066 Payment for acquisition, exploration and developments costs (80,318) (105,646) (53,011) Payment for additions to other property and assets (1,078) (3,732) (701) ------------ ------------ ------------ Net cash used in investing activities (483,422) (107,634) (52,496) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from long-term debt 570,560 266,905 263,723 Proceeds from short-term debt 31,750 39,000 - Proceeds from sale of capital stock, options and warrants 828 1,104 1,785 Proceeds from issuance of preferred stock 85,000 - - Proceeds from issuance of common units (See Note 2) 244,690 - - Principal payments of long-term debt (423,560) (207,011) (248,144) Principal payments of short-term debt (40,000) (21,000) - Costs incurred to redeem long-term debt - - (6,468) Debt issue and other costs incurred in connection with acquisition (See Note 9) (6,138) - - Debt issue and other costs incurred in connection with public offering (See Note 2) (9,937) - - Other (4,571) (474) (1,020) ------------ ------------ ------------ Net cash provided by financing activities 448,622 78,524 9,876 ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents 2,830 1,197 (3,612) Cash and cash equivalents, beginning of year 3,714 2,517 6,129 ------------ ------------ ------------ Cash and cash equivalents, end of year $ 6,544 $ 3,714 $ 2,517 ============ ============ ============
See notes to consolidated financial statements. F-5 PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (in thousands)
Series D Series E Cumulative Cumulative Additional Accumu- Convertible Convertible Paid-In lated Preferred Stock Preferred Stock Common Stock Capital Deficit ------------------------ ----------------------- ----------------------- ------------- ------------ Shares Amount Shares Amount Shares Amount ---------- ------------ ---------- ----------- ---------- ----------- BALANCE AT DECEMBER 31, 1995 - $ - - $ - 16,179 $ 1,618 $ 118,090 $ (42,679) Capital stock issued upon exercise of options and other - - - - 340 34 1,961 - Net income for the year - - - - - - - 16,548 ---------- ------------ ---------- ----------- ---------- ----------- ------------- ------------- BALANCE AT DECEMBER 31, 1996 - - - - 16,519 1,652 120,051 (26,131) Capital stock issued upon exercise of options and other - - - - 184 18 1,936 - Issuance of preferred stock and warrant in connection with an acquisition 47 20,508 - - - - 900 - Dividends on preferred stock - 163 - - - - - (163) Net income for the year - - - - - - - 14,259 ---------- ------------ ---------- ----------- ---------- ----------- ------------- ------------- BALANCE AT DECEMBER 31, 1997 47 20,671 - - 16,703 1,670 122,887 (12,035) Capital stock issued upon exercise of options and other - - - - 179 18 1,792 - Issuance of preferred stock - - 170 85,000 - - - - Dividends on preferred stock - 1,275 3 3,487 - - - (4,762) Net loss for the year - - - - - - - (58,554) ---------- ------------ ---------- ----------- ---------- ----------- ------------- ------------- BALANCE AT DECEMBER 31, 1998 47 $ 21,946 173 $ 88,487 16,882 $ 1,688 $ 124,679 $ (75,351) ========== ============ ========== =========== ========== =========== ============= =============
See notes to consolidated financial statements. F-6 PLAINS RESOURCES INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - ACCOUNTING POLICIES Principles of Consolidation and Presentation The consolidated financial statements include the accounts of Plains Resources Inc. (the "Company"), its wholly-owned subsidiaries and Plains All American Pipeline, L.P. ("PAA") in which the Company has an approximate 57% ownership interest and serves as its sole general partner (See Note 2). For financial statement purposes, the assets, liabilities and earnings of PAA are included in the Company's consolidated financial statements, with the public unitholders' interest reflected as a minority interest. All material intercompany accounts and transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform with the current year presentation. The Company is an independent energy company engaged in the acquisition, exploitation, development, exploration and production of crude oil and natural gas. Through its majority ownership in PAA, the Company is engaged in the midstream activities of marketing, transportation, terminalling and storage of crude oil. The Company's upstream oil and natural gas activities are focused in California in the Los Angeles Basin (the "LA Basin"), the Arroyo Grande Field and the Mt. Poso Field (collectively the "California Properties"), the Sunniland Trend of South Florida (the "Sunniland Trend") and the Illinois Basin in southern Illinois (the "Illinois Basin"). The Company's midstream activities are concentrated in California, Texas, Oklahoma, Louisiana and the Gulf of Mexico. 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. Estimates made by management include: oil and natural gas reserves, depreciation, depletion and amortization, including future abandonment costs, income taxes and related valuation allowance and pension 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. The Company's cash management program results in book overdraft balances which have been reclassified to current liabilities. 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. Oil and Natural Gas Properties The Company follows 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 the Company's 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 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 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 18). F-7 Crude Oil Pipeline Gathering and Terminal Assets Crude oil pipeline, gathering and terminal assets are recorded at cost and consist primarily of (i) crude oil pipeline facilities (primarily the All American Pipeline System and SJV Gathering System), (ii) crude oil terminal and storage facilities (primarily the Cushing Terminal), and (iii) trucking equipment, injection stations and other. Depreciation is computed using the straight-line method over estimated useful lives of 5 to 40 years. Pipeline facilities are depreciated over estimated useful lives of twenty-five to forty years. Depreciation on the Cushing Terminal is provided based on a useful life of forty years. 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. Pipeline Linefill Pipeline linefill 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. The Company owns approximately 5.0 million barrels of crude oil that is used to maintain the All American Pipeline's 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. Debt Issue Costs 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. Federal and State Income Taxes Income taxes are accounted for in accordance with Statement of Financial Accounting Standards ("SFAS ") No. 109, Accounting for Income Taxes. 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. Marketing, Transportation, Storage and Terminalling Revenues 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 the Company, which typically occurs upon receipt of the product by the Company. Except for crude oil purchased from time to time as inventory to service the needs of its terminalling and storage customers and working requirements of third party pipelines, the Company's policy is to purchase only crude oil for which it has a market to sell and to structure its sales contracts so that crude oil price fluctuations do not materially affect the gross margin which it receives. As the Company purchases crude oil, it establishes 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 New York Mercantile Exchange ("NYMEX"). Through these transactions, the Company seeks to maintain a position that is substantially balanced between crude oil purchases and sales and future delivery obligations. Terminalling and storage revenues are recognized at the time service is performed. As a regulated interstate pipeline, revenues for the transportation of crude oil on the All American Pipeline is recognized based upon Federal Energy Regulatory Commission ("FERC") and the Public Utilities Commission of the State of California ("CPUC") filed tariff rates and the related transported volume. Tariff revenue is recognized at the time such volume is delivered. Hedging The Company utilizes various derivative instruments to hedge its exposure to price fluctuations on oil and natural gas transactions. The derivative instruments used consist primarily of futures and option contracts traded on the NYMEX and crude oil swap contracts entered into with financial institutions. These instruments are utilized to hedge transactions which are based on NYMEX oil and gas prices; therefore, a high correlation exists between the hedged item and the hedge contract. The Company has entered into interest rate swaps to manage the interest rate exposure on certain of its long-term debt. F-8 Recognized gains and losses on hedge contracts are reported as a component of the related transaction. Results for hedging transactions are reflected in oil and natural gas sales to the extent related to the Company's oil and natural gas production and in marketing, transportation, storage and terminalling revenues to the extent related to such activities. Cash flows from hedging activities are included in operating activities in the Consolidated 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 accounts payable and other current liabilities in the Consolidated Balance Sheets. Deferred gains or losses from inventory hedges are included as part of the inventory cost and recognized when the related inventory is sold. Crude oil swap contracts have no carrying value and therefore are not reflected in the Consolidated Balance Sheets. Amounts paid or received from interest rate swaps are charged or credited to interest expense over the term of the swap. Stock Options In October 1995, the Financial Accounting Standards Board ("FASB") issued Statement No. 123 ("SFAS 123"), Accounting for Stock Based Compensation. In accordance with the provisions of SFAS No. 123, the Company applies APB Opinion 25 and related interpretations in accounting for its stock option plans (See Note 12). 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 ("FAS 133"). FAS 133 is effective for all fiscal years beginning after June 15, 1999 (January 1, 2000 for the Company). FAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, the type of hedge transaction. For fair-value hedge transactions in which the Company is hedging changes in an asset's, liability's, or firm commitment's fair value, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the hedged item's fair value. For cash-flow hedge transactions in which the Company is hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The Company has not yet determined the impact that the adoption of FAS 133 will have on its earnings or financial position. In November 1998, the Emerging Issues Task Force ("EITF") released Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities". EITF 98-10 deals with entities that enter into derivatives and other third-party contracts for the purchase and sale of a commodity in which they normally do business (for example, crude oil and natural gas). The EITF reached a consensus that energy trading contracts should be measured at fair value determined as of the balance sheet date with the gains and losses included in earnings and separately disclosed in the financial statements or footnotes thereto. The EITF acknowledged that determining whether or when an entity is involved in energy trading activities is a matter of judgment that depends on the relevant facts and circumstances. As such, certain factors or indicators have been identified by the EITF which should be considered in evaluating whether an operation's energy contracts are entered into for trading purposes. EITF 98-10 is required to be applied to financial statements issued by the Company beginning in 1999. The adoption of this consensus is not expected to have a material impact on the Company's results of operations or financial position. NOTE 2 - PAA - INITIAL PUBLIC OFFERING AND CONCURRENT TRANSACTIONS - - ------------------------------------------------------------------ The Company's midstream activities are conducted through PAA. PAA was formed during 1998 to acquire and operate the business and assets of the Company's wholly-owned midstream subsidiaries (the "Plains Midstream Subsidiaries"). Plains All American Inc. ("PAAI" or the "General Partner"), a wholly owned subsidiary of the Company, is the general partner of PAA. On November 23, 1998, PAA completed an initial public offering (the "IPO") of 13,085,000 common units representing limited partner interests (the "Common Units") in PAA and received therefrom net proceeds of approximately $244.7 million. Concurrently with the closing of the IPO, certain transactions described in the following paragraphs were consummated in connection with the formation of PAA. Such transactions and the transactions which occurred in conjunction with the IPO are referred to herein as the "Transactions". Certain of the Plains Midstream Subsidiaries were merged into the Company, which sold the assets of these subsidiaries to PAA in exchange for $64.1 million and the assumption of $11 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, which it purchased in July 1998 for approximately $400 million (See Note 9), to PAA in exchange for (i) 6,974,239 Common Units, 10,029,619 Subordinated F-9 Units and an aggregate 2% general partner interest in PAA, (ii) the right to receive Incentive Distributions; and (iii) the assumption by PAA of $175 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 the Company, PAA distributed approximately $177.6 million to the General Partner and used approximately $3 million of the remaining proceeds to pay expenses incurred in connection with the Transactions. 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 balance, $56.6 million, was distributed to the Company, which used the cash to repay indebtedness and for other general corporate purposes. In addition, concurrently with the closing of the IPO, PAA entered into a $225 million bank credit agreement (the "Bank Credit Agreement") that includes a $175 million term loan facility (the "Term Loan Facility") and a $50 million revolving credit facility (the "PAA Revolving Credit Facility") (See Note 4). During 1998, the Company recognized a pretax gain (net of approximately $9.2 million in formation related expenses) in connection with the formation of PAA. Such gain is the result of an increase in the book value of the Company's equity in PAA to reflect their proportionate share of the underlying net assets of PAA due to the sale of units in the IPO. 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. NOTE 3 - INVENTORY AND OTHER ASSETS - - ----------------------------------- Inventory consists of the following: December 31, --------------------------- 1998 1997 ------------ ------------ (in thousands) Crude oil $ 37,702 $ 18,986 Materials and supplies 4,818 3,816 ------------ ------------ $ 42,520 $ 22,802 ============ ============ At December 31, 1998 and 1997, approximately 76% and 77%, respectively, of the crude oil inventory volumes were hedged with NYMEX futures contracts or short-term physical delivery contracts. The unhedged inventory is comprised of working inventory and linefill primarily at the Cushing Terminal. Other assets consist of the following: December 31, ------------------------------- 1998 1997 --------------- -------------- (in thousands) Pipeline linefill $ 54,511 $ - Deferred tax asset (See Note 7) 47,785 796 Land 8,853 8,853 Debt issue costs 19,026 8,718 Other 9,218 2,776 --------------- -------------- 139,393 21,143 Accumulated amortization (6,318) (4,412) --------------- -------------- $133,075 $ 16,731 =============== ============== F-10 NOTE 4 - LONG-TERM DEBT AND CREDIT FACILITIES - - --------------------------------------------- Long-term debt consists of the follows:
December 31, -------------------------- 1998 1997 ------------ ------------ (in thousands) Revolving Credit Facility, bearing interest at weighted average interest rates of 6.9% and 7.3%, at December 31, 1998 and 1997, respectively $ 52,000 $ 80,000 PAA Bank Credit Agreement, bearing interest at 6.75% at December 31, 1998. 175,000 - 10.25% Senior Subordinated Notes, due 2006, net of unamortized premium of $2.4 million and $2.7 million at December 31, 1998 and 1997, respectively 202,427 202,661 Other long-term debt 3,067 3,578 ------------ ------------ Total long-term debt 432,494 286,239 Less current maturities (511) (511) ------------ ------------ $ 431,983 $ 285,728 ============ ============
Revolving Credit Facility The Company has a $225 million revolving credit facility (the "Revolving Credit Facility") with a group of banks (the "Lenders"). The Revolving Credit Facility is guaranteed by all of the Company's upstream subsidiaries and is collateralized by the oil and gas properties of the Company and the guaranteeing subsidiaries and the stock of all upstream subsidiaries. The borrowing base under the Revolving Credit Facility at December 31, 1998, is $225 million and is subject to redetermination from time to time by the Lenders in good faith, in the exercise of the Lenders' sole discretion, and in accordance with customary practices and standards in effect from time to time for oil and natural gas loans to borrowers similar to the Company. Such borrowing base may be affected from time to time by the performance of the Company's oil and natural gas properties and changes in oil and natural gas prices. The Company incurs a commitment fee of 3/8% per annum on the unused portion of the borrowing base. The Revolving Credit Facility, as amended, matures on July 1, 2000, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing October 1, 2000, with a final maturity of July 1, 2005. The Revolving Credit Facility bears interest, at the Company's option of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 1998, outstanding borrowings under the Revolving Credit Facility were $52 million. The Revolving Credit Facility contains covenants which, among other things, prohibit the payment of cash dividends, limit the amount of consolidated debt, limit the Company's ability to make certain loans and investments, and provides that the Company must maintain a Current Ratio, as defined, of 1:1. 10.25% Senior Subordinated Notes Due 2006 The Company has $200 million principal amount of 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") outstanding which bear a coupon rate of 10.25% and consist of (i) Series A - $.5 million principal amount; (ii) Series B - $149.5 million principal amount; (iii) Series C - $50,000 principal amount and (iv) Series D - $49.95 million principal amount. The Series A & B 10.25% Notes were issued in 1996 at 99.38% of par to yield 10.35%. Proceeds from the sale of the Series A and B 10.25% Notes, net of offering costs, were approximately $144.6 million and were used to redeem the Company's 12% Senior Subordinated Notes due 1999 (the "12% Notes") at 106% of the $100 million principal amount outstanding and to retire $42 million of bridge bank indebtedness which was incurred in December 1995 in connection with the acquisition of the Company's Illinois Basin properties. The 12% Notes were redeemed in April 1996, and the Company recognized an extraordinary loss of $8.5 million, $5.1 million net of deferred income taxes, in connection therewith. The Series C & D 10.25% Notes were issued in 1997 at approximately 107% of par to yield a minimum yield to worst of 8.79%, or 9.03% to maturity. Proceeds from the sale of the Series C & D 10.25% Notes, net of offering costs, were approximately $53 million and were used to reduce the balance on the Revolving Credit Facility. F-11 The 10.25% Notes are redeemable, at the option of the Company, 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. In addition, prior to March 15, 1999, up to $45 million in principal amount of the Series A & B 10.25% Notes and up to $15 million in principal amount of the Series C & D 10.25% Notes are redeemable at the option of the Company, in whole or in part, from time to time, at 110.25% of the principal amount thereof, with the Net Proceeds of any Public Equity Offering (as both are defined in the indenture under which the 10.25% Notes were issued (the "Indenture")). The Indenture contains covenants including, but not limited to the following: (i) limitations on incurrence of additional indebtedness; (ii) limitations on certain investments; (iii) limitations on restricted payments; (iv) limitations on dispositions of assets; (v) limitations on dividends and other payment restrictions affecting subsidiaries; (vi) limitations on transactions with affiliates; (vii) limitations on liens; and (viii) restrictions on mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, the Company will be required to make an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase. The 10.25% Notes are unsecured general obligations of the Company and are subordinated in right of payment to all existing and future senior indebtedness of the Company and are guaranteed by all of the Company's principal subsidiaries. PAA Credit Facilities Bank Credit Agreement. PAA has a $225 million Bank Credit Agreement which consists of the $175 million Term Loan Facility and the $50 million PAA Revolving Credit Facility. The $50 million PAA Revolving Credit Facility is used for capital improvements and working capital and general business purposes and contains a $10 million sublimit for letters of credit issued for general corporate purposes. The Bank Credit Agreement is secured by a lien on substantially all of the assets of PAA. The Term Loan Facility bears interest at PAA's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. PAA has two 10-year interest rate swaps (subject to cancellation by the counter party after seven years) aggregating $175 million notional principal amount, which fix the LIBOR portion of the interest rate (not including the applicable margin) at a weighted average rate of approximately 5.24%. Borrowings under the Revolving Credit Facility bear interest at PAA's option at either (i) the Base Rate, as defined, or (ii) reserve-adjusted LIBOR plus an applicable margin. PAA incurs a commitment fee on the unused portion of the PAA Revolving Credit Facility and, with respect to each issued letter of credit, an issuance fee. At December 31, 1998, PAA had $175 million outstanding under the Term Loan Facility, which amount represents indebtedness assumed from the General Partner. The Term Loan Facility matures in seven years, and no principal is scheduled for payment prior to maturity. The Term Loan Facility may be prepaid at any time without penalty. The PAA Revolving Credit Facility expires in two years. All borrowings for working capital purposes outstanding under the PAA Revolving Credit Facility must be reduced to no more than $8 million for at least 15 consecutive days during each fiscal year. At December 31, 1998, there are no amounts outstanding under the PAA Revolving Credit Facility. Letter of Credit Facility Simultaneously with the IPO, PAA entered into a $175 million secured letter of credit and borrowing facility with BankBoston, N.A. ("BankBoston"), ING (U.S.) Capital Corporation ("ING Baring") and certain other lenders (the "Letter of Credit Facility"), which replaced the existing facility for the benefit of one of the Plains Midstream Subsidiaries. The purpose of the Letter of Credit Facility is to provide (i) standby letters of credit to support the purchase and exchange of crude oil for resale and (ii) borrowings to finance crude oil inventory which has been hedged against future price risk or has been designated as working inventory. The Letter of Credit Facility is collateralized by a lien on substantially all of the assets of PAA. Aggregate availability under the Letter of Credit Facility for direct borrowings and letters of credit is limited to a borrowing base which is determined monthly based on certain current assets and current liabilities of PAA, primarily crude oil inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil. At December 31, 1998, the borrowing base under the Letter of Credit Facility was approximately $175 million. The Letter of Credit Facility has a $40 million sublimit for borrowings to finance crude oil purchased in connection with operations at PAA's crude oil terminal and storage facilities. All purchases of crude oil inventory financed are required to be hedged against future price risk on terms acceptable to the lenders. At December 31, 1998, approximately $9.8 million was F-12 outstanding under the sublimit. At December 31, 1997, approximately $18 million in borrowings was outstanding under a similar sublimit under a previous credit facility. Letters of credit under the Letter of Credit Facility are generally issued for up to 70 day periods. Borrowings bear interest at PAA's option at either (i) the Base Rate (as defined) or (ii) reserve-adjusted LIBOR plus the applicable margin. PAA incurs a commitment fee on the unused portion of the borrowing sublimit under the Letter of Credit Facility and an issuance fee for each letter of credit issued. The Letter of Credit Facility expires July 31, 2001. At December 31, 1998 and 1997, there were outstanding letters of credit of approximately $62 million and $38 million, respectively, issued under the Letter of Credit Facility and a previous letter of credit facility, respectively. To date, no amounts have been drawn on such letters of credit issued by PAA or the Plains Midstream Subsidiaries. Both the Letter of Credit Facility and the Bank Credit Agreement contain a prohibition on distributions on, or purchases or redemption's of, Units if any Default or Event of Default (as defined) is continuing. In addition, both facilities contain various covenants limiting the ability of PAA to (i) incur indebtedness, (ii) grant certain liens, (iii) sell assets in excess of certain limitations, (iv) engage in transactions with affiliates, (v) make investments, (vi) enter into hedging contracts and (vii) enter into a merger, consolidation or sale of its assets. In addition, the terms of the Letter of Credit Facility and the Bank Credit Agreement require PAA to maintain (i) a Current Ratio (as defined) of 1.0 to 1.0; (ii) a Debt Coverage Ratio (as defined) which is not greater than 5.0 to 1.0; (iii) an Interest Coverage Ratio (as defined) which is not less than 3.0 to 1.0; (iv) a Fixed Charge Coverage Ratio (as defined) which is not less than 1.25 to 1.0; and (v) a Debt to Capital Ratio (as defined) of not greater than .60 to 1.0. In both the Letter of Credit Facility and the Bank Credit Agreement, a Change in Control (as defined) of the Company constitutes an Event of Default. Maturities The aggregate amount of maturities of all long-term indebtedness for the next five years is: 1999 - $.5 million, 2000 - $3.1 million, 2001 - $10.9 million, 2002 - $10.9 million and 2003 - $10.9 million. NOTE 5 - CAPITAL STOCK - - ---------------------- Common Stock The Company has authorized capital stock consisting of 50 million shares of common stock, $.10 par value, and 2 million shares of preferred stock, $1.00 par value. At December 31, 1998, there were 16.9 million shares of common stock ("Common Stock") issued and outstanding and 219,424 shares of preferred stock outstanding. Stock Warrants and Options At December 31, 1998, the Company had warrants outstanding which entitle the holders thereof to purchase an aggregate one million shares of Common Stock. Per share exercise prices and expiration dates for the warrants are as follows: 750,000 shares at $6.00 expiring in 1999, 100,000 shares at $7.50 expiring in 2000 and 150,000 shares at $25.00 expiring in 2002. The Company has various stock option plans for its employees and directors (See Note 12). Series D Cumulative Convertible Preferred Stock In November 1997, the Company issued 46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D Preferred Stock") in connection with the acquisition of the Arroyo Grande Field (See Note 8). The Series D Preferred Stock has an aggregate stated value of $23.3 million and is redeemable at the Company's 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 of stated value for each share of Common Stock to be issued. Commencing January 1, 2000, the Series D Preferred Stock will bear an annual dividend of $30 per share. Prior to such date, no dividends will accrue. 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. This discount will be amortized to retained earnings during the two year period dividends do not accrue. F-13 Redeemable Preferred Stock On July 29, 1998, the Company sold in a private placement 170,000 shares of its Series E Preferred Stock for $85 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 the Company's 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 the Company's 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 the option of the Company after March 31, 1999, at 110% of stated value and at declining amounts 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 the Company's capital contribution to PAAI to acquire all of the outstanding capital stock of the Celeron Companies (See Note 9). On October 1, 1998, the Company paid a dividend on the Series E Preferred Stock for the period from July 29, 1998 through September 30, 1998. The dividend amount of approximately $1.4 million was paid by issuing 2,824 additional shares of the Series E Preferred Stock. After payment of such dividend, there were 172,824 shares of the Series E Preferred Stock outstanding with a liquidation value, including accrued dividends through December 31, 1998, of approximately $88.5 million. NOTE 6 - EARNINGS PER SHARE - - --------------------------- In February 1997, the FASB issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS"). Basic EPS excludes dilutive securities and is computed by dividing income available to common stockholders by the weighted-average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if dilutive securities were converted into common stock and is computed similarly to fully diluted EPS pursuant to previous accounting pronouncements. The following is a reconciliation of the numerators and the denominators of the basic and diluted EPS computations for income from continuing operations for the years ended December 1998, 1997 and 1996, as required by SFAS 128. All prior period EPS data has been restated in accordance with the provisions of SFAS 128.
For the Year Ended December 31, ------------------------------------------------------------------------------------------------------- 1998 1997 1996 ---------------------------------- ---------------------------------- --------------------------------- 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 ------------ ----------- --------- ------------ ---------- ---------- ----------- ---------- --------- (in thousands) Income before extraordinary item $ (63,316) $ 14,259 $ 21,652 Less: preferred stock dividends - (163) - ------------ ------------ ----------- Income available to common stockholders (63,316) 16,816 $ (3.77) 14,096 16,603 $ 0.85 21,652 16,384 $ 1.32 ========= ========== ========= Effect of dilutive securities: Employee stock options - - - 1,085 - 839 Warrants - - - 516 - 421 ------------ ----------- ------------ ---------- ----------- ---------- Income available to common stockholders assuming dilution $ (63,316) 16,816 $ (3.77) $ 14,096 18,204 $ 0.77 $ 21,652 17,644 $ 1.23 ============ =========== ========= ============ ========== ========== =========== ========== =========
Certain options and warrants to purchase shares of Common Stock were not included in the computations of diluted EPS because the exercise prices were greater than the average market price of the Common Stock during the periods of the EPS calculations, resulting in antidilution. In addition, the Series E Preferred Stock, which was issued during 1998, and the Company's F-14 Series D Preferred Stock, which was issued during 1997, is convertible into Common Stock but was not included in the computation of diluted EPS because the effect was antidilutive. See Notes 5 and 12 for additional information concerning outstanding options and warrants. NOTE 7 - INCOME TAXES - - --------------------- The Company's deferred income tax assets (liabilities) at December 31, 1998 and 1997, 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 the Company's upstream oil and gas operations and its midstream activities as follows: December ------------------------- 1998 1997 ------------ ----------- U.S. Federal Deferred tax assets: Net operating losses $ 48,911 $ 60,055 Percentage depletion 2,450 2,450 Tax credit carryforwards 1,614 1,010 Other 1,354 335 ------------ ----------- 54,329 63,850 Deferred tax liabilities: Oil and gas acquisition, exploration and development costs - (53,873) Marketing and pipeline depreciation and related adjustments (3,758) (2,243) ------------ ----------- Net deferred tax asset 50,571 7,734 Valuation allowance (2,786) (6,938) ------------ ----------- $ 47,785 $ 796 ============ =========== States Deferred tax liability $ (3,714) $ (958) ============ =========== At December 31, 1998, the Company has a net deferred tax asset of $47.8 million. Management believes that it is more likely than not that it will generate taxable income sufficient to realize such asset based on certain tax planning strategies available to the Company. As an example, the Company, through its existing ownership in PAA which is publicly traded, could generate sufficient taxable income to utilize the tax asset existing at December 31, 1998. Therefore, the Company has concluded that the valuation allowance is adequate. In the fourth quarter of 1998, as a result of the formation of PAA, significant taxable income was generated allowing the Company to utilize certain net operating losses ("NOLs") generated in past years. The use of such NOLs has permitted the Company to revise the valuation allowance previously associated with a portion of those NOLs. The benefit of NOL carryforwards recognized during the current year totaled approximately $5.0 million. In the first quarter of 1996, the Company reduced its valuation allowance resulting in the recognition of an $11 million credit to deferred income tax expense. The remaining deferred tax asset was not recognized primarily due to limitations imposed by the IRS regarding the utilization of NOLs generated prior to certain of the Company's subsidiaries being acquired and the uncertainty of utilizing the Company's investment tax credit ("ITC") carryforwards. At December 31, 1998, the Company had carryforwards of approximately $139.7 million of regular tax NOLs, $7.0 million of statutory depletion, $.3 million of ITC and $1.3 million of alternative minimum tax ("AMT") credit. Utilization of a portion of the ITC carryforwards is limited to certain companies within the consolidated group. At December 31, 1998, the Company had approximately $128.3 million of AMT NOL carryforwards available as a deduction against future AMT income. The NOL carryforwards expire from 2003 through 2011. F-15 Set forth below is a reconciliation between the income tax provision computed at the United States statutory rate on income before income taxes and the income tax provision per the accompanying Consolidated Statements of Operations:
Year Ended December 31, ----------------------------------------- 1998 1997 1996 ------------ ------------ ----------- (in thousands) U.S. federal income tax provision at statutory rate $ (35,446) $ 7,905 $ 6,214 State income taxes (5,094) 376 888 Valuation allowance adjustment (4,987) - (11,000) Full cost ceiling test limitation 2,903 - - Other (96) 46 - ------------ ------------ ----------- Income taxes on income before extraordinary item (42,720) 8,327 (3,898) Income tax benefit allocated to extraordinary item - - (3,403) ------------ ------------ ----------- Income tax (benefit) provision $ (42,720) $ 8,327 $ (7,301) ============ ============ ===========
In accordance with certain provisions of the Tax Reform Act of 1986, a change of greater than 50% of the beneficial ownership of the Company within a three-year period (an "Ownership Change") will place an annual limitation on the Company's ability to utilize its existing tax carryforwards. Under the Final Treasury Regulations issued by the Internal Revenue Service, the Company does not believe that an Ownership Change has occurred as of December 31, 1998. NOTE 8 - UPSTREAM ACQUISITIONS AND DISPOSITIONS - - ----------------------------------------------- During 1998, the Company 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 1,200 barrels of oil per day of 15-17 degree API gravity crude and added approximately 8 million barrels of oil equivalent to the Company's proved reserves. In March 1997, the Company completed the acquisition of Chevron USA's ("Chevron") interest in the Montebello Field for $25 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 the Company's existing California operations, was producing approximately 800 barrels of oil and 800 Mcf of gas per day and added approximately 23 million barrels of oil equivalent to the Company's proved reserves. The acquisition was funded with proceeds from the Revolving Credit Facility. In November 1997, the Company 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 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 oil per day from 70 wells and added approximately 20 million barrels of oil equivalent to the Company's proved reserves. The aggregate purchase price of $22.1 million 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 per share. No proved reserves had been assigned to the rights to the property interest conveyed. During 1997 and 1996, the Company sold certain non-strategic oil and natural gas properties located primarily in Louisiana and Utah for net proceeds of approximately $2.7 million and $3.1 million, respectively. NOTE 9 - MIDSTREAM ACQUISITION - - ------------------------------ On July 30, 1998, PAAI, a wholly owned unrestricted subsidiary of the Company, as defined in the Indentures for the 10.25% Senior Subordinated Notes, acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the "Celeron Companies") from Wingfoot Ventures Seven, Inc., a wholly-owned subsidiary of The Goodyear Tire & Rubber Company ("Goodyear") for approximately $400 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline System, F-16 a 1,233-mile crude oil pipeline extending from California to Texas, and a 45-mile crude oil gathering system in the San Joaquin Valley of California, as well as other assets related to such operations. Financing for the acquisition was provided through (i) PAAI's $325 million, limited recourse bank facility with ING (U.S.) Capital Corporation, BankBoston, N.A. and other lenders (the "PAAI Credit Facility") (See Note 4) and (ii) an approximate $114 million capital contribution to PAAI by the Company. Approximately $29 million of such capital contribution was funded by cash flow and the Revolving Credit Facility and the remaining $85 million was provided by the issuance of the Series E Preferred Stock (See Note 5). The assets, liabilities and results of operations of the Celeron Companies are included in the Consolidated Financial Statements of the Company effective July 30,1998. The following unaudited pro forma information is presented to show pro forma revenues, net loss and net loss per share as if the acquisition occurred on January 1, 1997. Year Ended December 31, ---------------------------------- 1998 1997 --------------- -------------- (in thousands, except per share data) Revenues $ 1,731,746 $ 1,854,562 =============== ============== Net loss $ (51,110) $ (6,067) =============== ============== Net loss per share: Basic $ (3.60) $ (0.86) =============== ============== Diluted $ (3.60) $ (0.86) =============== ============== The pro forma net loss for the year ended December 31, 1997, includes a non-cash impairment charge of $64.2 million related to the writedown of pipeline assets and linefill by Wingfoot in connection with the sale of Wingfoot by Goodyear to the Company. Based on the Company's purchase price allocation to property and equipment and pipeline linefill, an impairment charge would not have been required had the Company actually acquired Wingfoot effective January 1, 1997. Excluding this impairment charge, the Company's pro forma net income for 1997 would have been $33.1 million, or $1.36 per share. The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 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 ============ NOTE 10 - RELATED PARTY TRANSACTIONS - - ------------------------------------- In conjunction with the IPO, the Company entered into various agreements with PAA, including (i) the Omnibus Agreement, providing for the resolution of certain conflicts arising from the conduct of PAA and the Company of related businesses and for the General Partner's indemnification of PAA for certain matters and (ii) the Crude Oil Marketing Agreement which provides for the marketing by PAA of the Company's crude oil production. PAA does not directly employ any persons to manage or operate its business. These functions are provided by employees of the General Partner and the Company. The General Partner does not receive a management fee or other F-17 compensation in connection with its management of PAA. PAA reimburses the General Partner and the Company for all direct and indirect costs of services provided, including the costs of employee, officer and director compensation and benefits properly allocable to PAA, and all other expenses necessary or appropriate to conduct the business of, and allocable to PAA. The PAA Partnership Agreement provides that the General Partner will determine the expenses that are allocable to PAA in any reasonable manner determined by the General Partner in its sole discretion. Total costs reimbursed to the General Partner and the Company by PAA were approximately $.5 million for 1998. Such costs include, (i) allocated personnel costs (such as salaries and employee benefits) of the personnel providing such services, (ii) rent on office space allocated to the General Partner in the Company's offices in Houston, Texas and (iii) out-of-pocket expenses related to the providing of such services. PAAI adopted its 1998 Long-Term Incentive Plan (the "Long-Term Incentive Plan") for employees and directors of PAAI and its affiliates who perform services for PAA. The Long-Term Incentive Plan consists of two components, a restricted unit plan (the "Restricted Unit Plan") and a unit option plan (the "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 PAAI'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. Approximately 500,000 Restricted Units were granted upon consummation of the IPO to employees of PAAI. In general, Restricted Units granted to employees during the Subordination Period (as defined in the PAA Partnership Agreement) will vest only upon, and in the same proportion as, the conversion of Subordinated Units to Common Units. PAAI will be entitled to reimbursement by PAA for the cost incurred in acquiring such Common Units. Unit Option Plan. The Unit Option Plan currently permits the grant of options ("Unit Options") covering Common Units. No grants will initially be made under the Unit Option Plan. The Compensation Committee may, in the future, determine to make grants under such plan to employees and directors containing such terms as the Committee shall determine. In addition to the grants made under the Restricted Unit Plan described above, PAAI agreed to transfer approximately 325,000 of its affiliates' Common Units to certain key employees of the General Partner (the "Transaction Grants"). Generally, approximately 72,000 of such Common Units will 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 ("MQD") 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 has been paid. In addition, approximately 36,000 of such Common Units will 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 MQD on all outstanding Common Units and Subordinated Units and the related distribution on the general partner interest. Any Common Units remaining unvested shall vest upon, and in the same proportion as, the conversion of Subordinated Units. The Company will recognize compensation expense in the future for the Restricted Units, Unit Options and Transaction Grants described above, when vesting becomes probable. NOTE 11 - RETIREMENT PLAN - - ------------------------- Effective June 1, 1996, the Company's Board of Directors adopted a nonqualified retirement plan (the "Plan") for certain officers of the Company. 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, 1998 and 1997, is comprised of the following components: Year Ended December 31, ------------------------- 1998 1997 ----------- ----------- (in thousands) Service cost - benefits earned during the period $ 97 $ 82 Interest on projected benefit obligation 74 60 Amortization of prior service cost 37 37 Unrecognized loss 3 - ----------- ----------- Net pension expense $ 211 $ 179 =========== =========== F-18 The following schedule reconciles the status of the Plan with amounts reported in the Company's balance sheet at December 31, 1998 and 1997.
December 31, ----------------------- 1998 1997 ---------- ---------- (in thousands) Actuarial present value of benefit obligations: Vested benefits $ 1,108 $ 857 Nonvested benefits 172 184 ---------- ---------- Accumulated benefit obligation 1,280 1,041 ========== ========== Projected benefit obligation for service rendered to date $ 1,280 $ 1,041 Plan assets at fair value - - ---------- ---------- Projected benefit obligation for service rendered to date 1,280 1,041 Unrecognized loss (211) (145) Prior service cost not yet recognized in net periodic pension expense (582) (619) ---------- ---------- Net pension liability 487 277 Adjustment required to recognize minimum liability 582 619 ---------- ---------- Accrued pension cost liability recognized in the balance sheet $ 1,069 $ 896 ========== ==========
The weighted-average discount rate used in determining the projected benefit obligation was 6.5% and 7% for the years ended December 31, 1998 and 1997, respectively. NOTE 12 - STOCK COMPENSATION PLANS - - ---------------------------------- Historically, the Company has used stock options as a long-term incentive for its 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 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25"), no compensation expense has been recognized in the accompanying financial statements. During 1996, the Company's shareholders approved the Company's 1996 Stock Incentive Plan, under which a maximum of 1.5 million shares of Common Stock were reserved for issuance. The Company also has options outstanding under its 1991 and 1992 plans, under which a maximum of 2.0 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 the Company's 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. In addition, during 1996, the Company granted performance options to purchase a total of 500,000 shares of Common Stock 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 of five years. The performance options vest when the price of the Common Stock trades at or above $24 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. A summary of the status of the Company's stock options as of December 31, 1998, 1997, and 1996, and changes during the years ending on those dates are presented below:
1998 1997 1996 -------------------- -------------------- -------------------- 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 2,614 $ 9.50 2,435 $ 8.56 1,728 $ 6.40 Granted 333 $ 16.62 384 $ 14.33 1,060 $ 11.34 Exercised (179) $ 6.71 (163) $ 6.80 (285) $ 6.26 Forfeited (19) $ 11.36 (42) $ 9.82 (68) $ 6.63 --------- --------- --------- Outstanding at end of year 2,749 $ 10.53 2,614 $ 9.50 2,435 $ 8.56 ========= ========= ========= Options exercisable at year-end 1,646 $ 8.53 1,494 $ 7.24 1,289 $ 6.78 ========= ========= ========= Weighted-average fair value of options granted during the year $ 4.93 $ 4.53 $ 3.19
F-19 In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 establishes 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 No. 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. The Company has elected to follow APB 25 and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS No. 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 the Company's 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. The Company will recognize compensation expense under APB 25 in the future for the two performance options described above, if certain conditions are met and such options vest. Pro forma information regarding net income and EPS is required by SFAS No. 123 and has been determined as if the Company had accounted for its 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 1998, 1997 and 1996: risk-free interest rates of 5.6% for 1998, 6.1% for 1997 and 6.0% for 1996; a volatility factor of the expected market price of the Company's common stock of .38 for 1998, .42 for 1997 and .36 for 1995; no expected dividends; and weighted-average expected option lives of 2.7 years in 1998, 2.6 years in 1997 and 2.7 years in 1996. 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 the Company's 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. Set forth below is a summary of the Company's net income and EPS as reported and pro forma as if the fair value based method of accounting defined in SFAS No. 123 had been applied. The pro forma information is not meant to be representative of the effects on reported net income 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.
Year Ended December 31, ------------------------------------------------------------------------------- 1998 1997 1996 ------------------------- ------------------------- ------------------------- As Pro As Pro As Pro Reported Forma Reported Forma Reported Forma ------------ ------------ ------------ ------------ ------------ ------------ Net income/(loss) (in thousands) $(58,554) $(59,262) $ 14,259 $ 13,665 $ 16,548 $ 16,161 Basic EPS $ (3.77) $ (3.81) $ 0.85 $ 0.81 $ 1.01 $ 0.99 Diluted EPS $ (3.77) $ (3.81) $ 0.77 $ 0.74 $ 0.94 $ 0.92
The following table summarizes information about stock options outstanding at December 31, 1998:
Weighted Average Weighted Weighted Number Remaining Average Number Average Range of Outstanding Contractual Exercise Exercisable Exercise Exercise Price at 12/31/98 Life Price at 12/31/98 Price - - ----------------------- ------------ ------------- ------------ ------------- ------------ (share amounts in thousands) $ 5.25 to $ 6.75 917 3.8 years $ 6.14 899 $ 6.13 $ 7.50 to $ 7.81 445 4.3 years $ 7.65 369 $ 7.63 $10.50 to $ 15.63 1,282 3.1 years $ 13.96 273 $ 13.53 $19.19 to $ 19.19 105 4.4 years $ 19.19 105 $ 19.19 --------- --------- $ 5.25 to $ 19.19 2,749 3.6 years $ 10.53 1,646 $ 8.53 ========= =========
During 1998, 1997 and 1996, pursuant to Board of Directors' resolutions, the Company contributed approximately 28,000, 21,000 and 18,000 shares, respectively, of Common Stock at weighted average prices of $16.21, $15.22 and $11.35 per share, respectively, on behalf of participants in the Company's 401(k) Savings Plan, representing a matching contribution by the Company for 50% of an employee's contribution. F-20 NOTE 13 - COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION - - --------------------------------------------------------------- Commitments and Contingencies Minimum commitments in connection with office space and office equipment leased by the Company are: 1999 - $1.8 million; 2000 and 2001 - $1.7 million annually; 2002 and 2003 - $1.6 million annually; thereafter - $4.1 million. Rental payments made under the terms of similar arrangements totaled approximately $1.3 million in 1998 and $1.1 million in 1997 and in 1996. In connection with its crude oil marketing, PAA provides certain purchasers and transporters with irrevocable standby letters of credit to secure PAA's obligation for the purchase of crude oil (See Note 4). Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 1998, PAA had outstanding letters of credit of approximately $62 million. Such letters of credit are secured by the crude oil inventory and accounts receivable of PAA (See Note 4). The Company incurred costs associated with leased land, rights-of-way, permits and regulatory fees of $.3 million during 1998. At December 31, 1998, minimum future payments, net of sublease income, associated with these contracts are approximately $.3 million for the following year. Generally these contracts extend beyond one year but can be canceled at any time should they not be required for operations. In order to receive electrical power service at certain remote locations, the Company has entered into facilities contracts with several utility companies. These facilities charges are calculated periodically based upon, among other factors, actual electricity energy used. Minimum future payments for these contracts at December 31, 1998, are approximately $760,000 annually for each of the next five years. Under the amended terms of an asset purchase agreement between the Company and Chevron, commencing with the year beginning January 1, 2000, and each year thereafter, the Company is required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 225. To the extent the Company elects not to plug and abandon the number of required wells, the Company is 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, the Company is 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 the Company does not expend the required amounts during a calendar year, the Company is required to contribute an amount equal to 125% of the actual shortfall to an escrow account. The Company may withdraw amounts from such escrow account to the extent it expends excess amounts in a future year. As of December 31, 1998, the Company has not been required to make contributions to an escrow account. Although the Company obtained environmental studies on its properties in California, the Sunniland Trend and the Illinois Basin and the Company believes 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 its California Properties, the Company 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. While the Company believes that it does not have any material obligations for operations conducted prior to the Company's acquisition of the properties from Chevron, other than its 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 it 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 the Company's 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. The Company has estimated that the costs to perform these tasks is approximately $12.8 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 ("DD&A"). Results from operations for 1998, 1997 and 1996 include $0.8 million, $0.6 million and $0.8 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected 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 18. F-21 As is common within the industry, the Company has entered into various commitments and operating agreements related to the exploration and development of and production from certain 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 the Company's financial position, results of operations or cash flows. In March 1999, PAA signed a definitive agreement to acquire Scurlock Permian LLC and certain other pipeline assets (See Note 21). Industry Concentration Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of trade receivables. The Company's accounts receivable are primarily from purchasers of oil and natural gas products. This industry concentration has the potential to impact the Company's 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. The Company generally requires letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be mitigated. There are a limited number of alternative methods of transportation for the Company's production. Substantially all of the Company's California crude oil and natural gas production and its Sunniland Trend and Illinois Basin 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 the Company for a reasonable fee could result in the Company having to find transportation alternatives, increased transportation costs to the Company or involuntary curtailment of a significant portion of its crude oil and natural gas production which could have a negative impact on future results of operations or cash flows. NOTE 14 - LITIGATION - - -------------------- During 1996, the Company settled two lawsuits filed in 1992 and 1993, relating to activities in 1991 and 1992, against certain of its officers and directors for a cash payment of approximately $6.3 million. Approximately $4.1 million of such amount was paid by the Company's insurance carrier and $2.2 million was paid by the Company. Taking into account prior costs incurred by the Company to defend these suits, and for which the Company agreed to relinquish its claims for reimbursement against its insurance company, this settlement resulted in a charge to 1996 first quarter earnings of $4 million. 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"), a wholly owned subsidiary of the Company, 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 the Company's oil and natural gas leases but denied such motion as to the counterclaim alleging conversion of funds. The Company has reached an agreement in principle with all parties to settle this case. In consideration for full and final settlement, and dismissal with prejudice of all issues in this case, the Company has agreed to pay to the defendants the total sum of $100,000, and release certain royalty amounts held in suspense and in the court registry during the pendency of this case. Finalization of this settlement has been delayed due to disputes over certain title issues. Motions have been filed requesting the Court to rule on the disputes, but no hearing date has been set. The Company does not believe that the disputes will adversely affect the settlement reached between the Company and the defendants. The Company, in the ordinary course of business, is a claimant and/or a defendant in various other legal proceedings in which its exposure, individually and in the aggregate, is not considered material to the consolidated financial statements. F-22 NOTE 15 - MAJOR CUSTOMERS - - ------------------------- Sales to Sempra Energy Trading Corporation ("Sempra") (formerly AIG Trading Corporation) and Koch Oil Company ("Koch") accounted for 27% and 15%, respectively, of the Company's total revenue (exclusive of interest and other income) during 1998. Customers accounting for more than 10% of total revenue for 1997 and 1996 were as follows: 1997 -- Koch -27% and Sempra - 11%, 1996 -- Koch-16% and Basis Petroleum, Inc. (formerly Phibro Energy USA, Inc.) - 11%. No other single customer accounted for as much as 10% of total sales during 1998, 1997 or 1996. Additionally during 1998, Tosco Refining Company and Scurlock Permian LLC accounted for approximately 50% and 17%, respectively, of the Company's oil and gas sales. NOTE 16 - FINANCIAL INSTRUMENTS - - ------------------------------- Derivatives The Company has only limited involvement with derivative financial instruments, as defined in SFAS No. 119, Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments and does not use them for speculative trading purposes. The Company's principle objective is to hedge exposure to price volatility on crude oil and natural gas. These arrangements expose the Company to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where the Company's production is less than expected. Substantially all derivatives are either exchange traded or with major financial institutions and the risk of loss is considered remote. The Company has entered into various arrangements to fix the NYMEX crude oil spot price ("NYMEX Crude Oil Price") for a significant portion of its crude oil production. On December 31, 1998, these arrangements provided for a NYMEX Crude Oil Price for 9,000 barrels per day from January 1, 1999, through December 31, 1999, at approximately $18.25 per barrel. Since December 31, 1998, the Company has entered into additional arrangements which provide for a NYMEX Crude Oil Price for 2,000 barrels per day from January 1, 2000, through December 31, 2000, at $15.30 per barrel. Location and quality differentials attributable to the Company's properties are not included in the foregoing prices. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX Crude Oil Price. Gains or losses are recognized in the month of related production and are included in oil and natural gas sales. In addition, the Company has entered into ten year swap agreements with various financial institutions to hedge the interest rate on an aggregate of $200 million of bank debt. Approximately $175 million of such debt relates to the Term Loan Facility of PAA and fixes the LIBOR portion of the interest rate on such loan at approximately 5.24%. The remaining $25 million swap locks in LIBOR at approximately 5.9%. Fair Value of Financial Instruments The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments. The estimated fair value amounts have been determined by the Company 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. F-23 The carrying amounts and fair values of the Company's other financial instruments are as follows:
December 31, ---------------------------------------------------------- 1998 1997 ---------------------------- ---------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ------------- ------------- ------------- ------------- (in thousands) Long Term Debt: Bank debt $ 227,000 $ 227,000 $ 80,000 $ 80,000 Subordinated debt 202,427 202,000 202,661 214,750 Other long-term debt 2,556 2,556 3,067 3,067 Redeemable Preferred Stock 88,487 88,487 - - Off Balance Sheet Financial Information: Unrealized gain on crude oil swap agreements (1) - 16,870 - 7,246 Unrealized loss on interest rate swap agreements - (3,253) - -
- - -------------------- (1) These amounts represent the calculated difference between the NYMEX Crude Oil Price and the hedge arrangements for future production of the Company's properties as of December 31, 1998 and 1997. Such hedges, and therefore the unrealized gains, have been included in estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 18. 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 the Company's incremental borrowing rate. The fair value of the Redeemable Preferred Stock is estimated to be its liquidation value at December 31, 1998. The fair value of the interest rate swap is based on the termination value at December 31, 1998. NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION - - ----------------------------------------------------------- Selected cash payments and noncash activities were as follows:
Year Ended December 31, --------------------------------------- 1998 1997 1996 ---------- ----------- ----------- (in thousands) Cash paid for interest (net of amount capitalized) $ 34,546 $ 20,486 $ 16,309 ========== =========== =========== Noncash investing and financing activities: Series D Preferred Stock Dividends $ 1,275 $ 163 $ - ========== =========== =========== Series E Preferred Stock Dividends $ 3,487 $ - $ - ========== =========== =========== Tax benefit from exercise of employee stock options $ 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) $ - ========== =========== ===========
F-24 NOTE 18 - OIL AND NATURAL GAS ACTIVITIES - - ----------------------------------------- Costs Incurred The Company's oil and natural gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred in connection therewith during the last three years.
Year Ended December 31, --------------------------------------- 1998 1997 1996 ------------ ------------ ----------- (in thousands) Property acquisitions costs: Unproved properties $ 6,266 $ 15,249 $ 728 Proved properties 3,851 28,182 3,087 Exploration costs 1,657 1,730 2,433 Exploitation and development costs 89,161 82,217 45,007 ------------ ------------ ----------- $ 100,935 $ 127,378 $ 51,255 ============ ============ ===========
Capitalized Costs The following table presents the aggregate capitalized costs subject to amortization relating to the Company's oil and natural gas acquisition, exploration, exploitation and development activities, and the aggregate related DD&A. Under full cost accounting rules as prescribed by the SEC, unamortized costs of proved 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 the Company's proved oil and natural gas properties exceeded the Standardized Measure and the Company recorded a non- cash, after tax charge to expense of $109.0 million ($173.9 million pre-tax). Year Ended December 31, ----------------------------- 1998 1997 ------------- -------------- (in thousands) Proved properties $ 596,203 $ 498,038 Accumulated DD&A (369,260) (171,162) ------------- -------------- $ 226,943 $ 326,876 ============= ============== The DD&A rate per equivalent unit of production excluding the writedown in 1998 was $3.00, $2.83 and $3.00 for the years ended December 31, 1998, 1997 and 1996, respectively. Costs Not Subject to Amortization The following table summarizes the categories of costs which comprise the amount of unproved properties not subject to amortization. December 31, ----------------------------- 1998 1997 ------------- -------------- (in thousands) Acquisition costs $ 47,657 $ 41,652 Exploration costs 2,467 2,573 Capitalized interest 4,421 7,799 ------------- -------------- $ 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. The Company 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 20%, 35% and 5% of the balance in unproved properties at December 31, 1998, related to additions made in 1998, 1997 and 1996, respectively. During 1998, 1997 and 1996, the Company capitalized $3.7 million, $3.3 million and $3.6 million, respectively, of interest related to the costs of unproved properties in the process of development. F-25 Supplemental Reserve Information (Unaudited) The following information summarizes the Company's net proved reserves of oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the three years ended December 31, 1998. The following reserve information is based upon reports of the independent petroleum consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc., Ryder Scott Company and System Technology Associates, Inc. The estimates are in accordance with regulations prescribed by the Securities and Exchange Commission ("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 the control of the Company. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of 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 oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future 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 oil and natural gas reserves attributable to the Company's 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 oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Almost all of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price at December 31, 1998, upon which proved reserve volumes, the estimated present value (discounted at 10%) of future net revenue from the Company's proved oil and natural gas reserves (the "Present Value of Proved Reserves") and the Standardized Measure as of such date were based, was $12.05 per barrel. Such price was the lowest year-end price since oil was deregulated in 1980 and was approximately 34% below the price used in preparing reserve estimates at the end of 1997. Estimated Quantities of Oil and Natural Gas Reserves (Unaudited) The following table sets forth certain data pertaining to the Company's proved and proved developed reserves for the three years ended December 31, 1998.
As of or for the Year Ended December 31, ----------------------------------------------------------------------------- 1998 1997 1996 ------------------------- ------------------------- ------------------------ Oil Gas Oil Gas Oil Gas (Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf) ------------ ------------ ------------ ----------- ----------- ----------- (in thousands) Proved Reserves Beginning balance 151,627 60,350 115,996 37,273 94,408 43,110 Revision of previous estimates (46,282) 2,925 (16,091) 3,805 19,424 6,641 Extensions, discoveries, improved recovery and other additions 14,729 29,306 17,884 8,126 8,179 1,294 Sale of reserves in-place - (2,799) (26) (547) (5) (12,491) Purchase of reserves in-place 7,709 - 40,764 14,566 45 862 Production (7,575) (3,001) (6,900) (2,873) (6,055) (2,143) ------------ ------------ ------------ ----------- ----------- ----------- Ending balance 120,208 86,781 151,627 60,350 115,996 37,273 ============ ============ ============ =========== =========== =========== Proved Developed Reserves Beginning balance 99,193 38,233 86,515 25,629 67,266 29,397 ============ ============ ============ =========== =========== =========== Ending balance 73,264 58,445 99,193 38,233 86,515 25,629 ============ ============ ============ =========== =========== ===========
F-26 Standardized Measure of Discounted Future Net Cash Flows (Unaudited) The Standardized Measure of discounted future net cash flows relating to proved oil and natural gas reserves is presented below:
December 31, ---------------------------------------------- 1998 1997 1996 ------------- ------------- ------------- (in thousands) Future cash inflows $ 1,102,863 $ 2,237,876 $ 2,681,007 Future development costs (117,924) (157,877) (111,785) Future production expense (546,091) (1,019,254) (977,551) Future income tax expense - (261,130) (437,654) ------------- ------------- ------------- Future net cash flows 438,848 799,615 1,154,017 Discounted at 10% per year (211,905) (387,792) (575,436) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 226,943 $ 411,823 $ 578,581 ============= ============= =============
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 the Company's proved properties and the present value thereof are made using 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 received by the Company at December 31, 1998, is based on the NYMEX Crude Oil Price of $12.05 per barrel with variations therefrom based on location and grade of crude oil. The Company has entered into various fixed price and floating price collar arrangements to fix or limit the NYMEX Crude Oil Price for a significant portion of its crude oil production. Arrangements in effect at December 31, 1998, are reflected in the reserve reports through the term of the arrangements (See Note 16). The overall average prices used in the reserve reports as of December 31, 1998, were $7.96 per barrel of crude oil, condensate and natural gas liquids and $1.68 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 Present Value of Proved Reserves to be $226.9 million, $511.0 million and $764.8 million at December 31, 1998, 1997 and 1996, respectively. SFAS No. 69 requires the Company to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by the Company in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal income tax rate to pretax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards. A large portion of the Company's reserve base (approximately 90% of year-end 1998 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. By comparison, using a NYMEX Crude Oil Price of $18.34 per barrel, results in a Present Value of Proved Reserves of $705 million and estimated net proved reserves of 219 million barrels of oil equivalent. Such information is based upon reserve reports prepared by independent petroleum engineers, in accordance with the rules and regulations of the SEC, using the same crude oil price used in preparing year-end 1997 reserve information. F-27 The principal sources of changes in the Standardized Measure of future net cash flows for the three years ended December 31, 1998, are as follows:
Year End December 31, ------------------------------------------- 1998 1997 1996 ------------- ------------- ------------- (in thousands) Balance, beginning of year $ 411,823 $ 578,581 $ 304,841 Sales, net of production expenses (51,927) (63,917) (58,866) Net change in sales and transfer prices, net of production expenses (288,320) (359,138) 275,200 Changes in estimated future development costs 42,858 9,927 (5,188) Extensions, discoveries and improved recovery, net of costs 21,095 84,676 50,013 Previously estimated development costs incurred during the year 25,501 23,449 19,662 Purchase of reserves in-place 14,173 74,278 2,253 Sales of reserves in-place (1,151) (1,501) (3,357) Revision of quantity estimates (91,942) (57,597) 145,815 Accretion of discount 51,099 76,477 36,678 Net change in income taxes 99,170 87,024 (124,254) Changes in estimated timing of production and other (5,436) (40,436) (64,216) ------------- ------------- ------------- Balance, end of year $ 226,943 $ 411,823 $ 578,581 ============= ============= =============
NOTE 19 - QUARTERLY FINANCIAL DATA (UNAUDITED) - - ---------------------------------------------- The following table shows summary financial data for 1998 and 1997.
Quarter Ended ------------------------------------------------------------------------- March 31, June 30, September 30, December 31, -------------- -------------- ----------------- ---------------- (in thousands, except per share data) 1998 Revenues $ 193,572 $ 189,441 $ 393,719 $ 456,545 (1) Operating profits 17,534 18,323 27,111 28,154 (1) Net income 1,431 1,418 3,625 (65,028) Basic EPS 0.07 0.07 0.11 (4.00) Diluted EPS 0.06 0.06 0.10 (4.00) 1997 Revenues $ 207,132 $ 188,592 $ 220,660 $ 245,860 Operating profits 18,609 18,666 18,567 20,874 Net income 3,891 3,252 2,759 4,357 Basic EPS 0.24 0.20 0.17 0.25 Diluted EPS 0.22 0.18 0.15 0.23
- - ------------------ (1) Excludes the net gain of $60.8 million recorded upon the formation of PAA. NOTE 20 - OPERATING SEGMENTS - - ---------------------------- The Company's operations consist of two operating segments: (1) Upstream Operations - engages in the acquisition, exploitation, development, exploration and production of crude oil and natural gas and (2) Midstream Operations - engages in crude oil gathering, marketing, terminalling, storage and transportation. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (See Note 1). The Company evaluates segment performance based on gross margin, gross profit and income before income taxes and extraordinary items. F-28 The following schedule summarizes certain segment information.
(In thousands) Upstream Midstream Total - - ------------------------------------------------------------------------------------------------------------ 1998 Revenues: External Customers $ 102,754 $ 1,129,689 $ 1,232,443 Intersegment (a) - 119 119 Interest income 250 584 834 -------------- ------------- ------------- Total revenues of reportable segments $ 103,004 $ 1,130,392 $ 1,233,396 ============== ============= ============= Segment gross margin (b)(d) $ 51,927 $ 38,361 $ 90,288 Segment gross profit (c)(d) 46,446 33,064 79,510 Segment income/(loss) before income taxes and extraordinary item (d) (175,926) 15,646 (160,280) Interest expense 23,099 12,631 35,730 Depreciation, depletion and amortization 199,523 5,371 204,894 Income tax expense (benefit) (47,283) 4,563 (42,720) Capital expenditures 100,935 405,508 506,443 Assets 364,059 610,208 974,267 - - ------------------------------------------------------------------------------------------------------------ 1997 Revenues: External Customers $ 109,403 $ 752,522 $ 861,925 Intersegment (a) - - - Interest 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 - - ------------------------------------------------------------------------------------------------------------ 1996 Revenues: External Customers $ 97,601 $ 531,698 $ 629,299 Intersegment (a) - - - Interest income 219 90 309 -------------- ------------- ------------- Total revenues of reportable segments $ 97,820 $ 531,788 $ 629,608 ============== ============= ============= Segment gross margin (b) $ 58,866 $ 9,531 $ 68,397 Segment gross profit (c) 54,111 6,557 60,668 Segment income before income taxes and extraordinary item 15,806 1,948 17,754 Interest expense 13,727 3,559 17,286 Depreciation, depletion and amortization 20,797 1,140 21,937 Income tax expense (benefit) (4,624) 726 (3,898) Capital expenditures 51,134 2,941 54,075 Assets 307,692 122,557 430,249 - - ------------------------------------------------------------------------------------------------------------
(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 the segments. F-29 The following schedule reconciles segment revenues to amounts reported in the Company's financial statements:
For the Year Ended December 31, ------------------------------------------ 1998 1997 1996 ------------- ----------- ----------- Revenues of reportable segments $ 1,233,396 $ 862,244 $ 629,608 Intersegment (119) - - Net gain recorded upon the formation of PAA not allocated to reportable segments 60,815 - - ------------- ----------- ----------- Total company revenues $ 1,294,092 862,244 629,608 ============= =========== ===========
NOTE 21 - SUBSEQUENT EVENT - - --------------------------- On March 17, 1999, PAA signed a definitive agreement with Marathon Ashland Petroleum LLC to acquire Scurlock Permian LLC and certain other pipeline assets. The cash purchase price for the acquisition is approximately $138 million, plus associated closing and financing costs. The purchase price is subject to adjustment at closing for working capital on April 1, 1999, the effective date of the acquisition. Closing of the transaction is subject to regulatory review and approval, consents from third parties, and customary due diligence. Subject to satisfaction of the foregoing conditions, the transaction is expected to close in the second quarter of 1999. PAA has received a financing commitment from one of its existing lenders, which in addition to other financial resources currently available to PAA, will provide the funds necessary to complete the transaction. The definitive agreement provides that if either party fails to perform its obligations thereunder through no fault of the other party, such defaulting party shall pay the nondefaulting party $7.5 million as liquidated damages. Scurlock Permian LLC, a wholly owned subsidiary of Marathon Ashland Petroleum LLC, is engaged in crude oil transportation, trading and marketing, operating in 14 states with more than 2,400 miles of active pipelines, numerous storage terminals and a fleet of more than 225 trucks. Its largest asset is an 800-mile pipeline and gathering system located in the Spraberry Trend in West Texas that extends into Andrews, Glasscock, Howard, Martin, Midland, Regan, Upton and Irion Counties, Texas. The assets to be acquired also include approximately one million barrels of crude oil used for linefill requirements. F-30 EX-10.M 2 1ST AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10(m) FIRST AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT THIS FIRST AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT (this "Amendment") dated as of the 17th day of November, 1998, by and among PLAINS RESOURCES INC., a Delaware corporation (the "Company"), ING (U.S.) CAPITAL CORPORATION, as Agent ("Agent"), and the Lenders under the Original Agreement (as defined herein). W I T N E S S E T H: WHEREAS, the Company, Agent and Lenders entered into that certain Fourth Amended and Restated Credit Agreement dated as of May 22, 1998 (the "Original Agreement") for the purposes and consideration therein expressed, pursuant to which Lenders became obligated to make and made loans to the Company as therein provided; and WHEREAS, the Company, Agent and Lenders desire to amend the Original Agreement for the purposes described herein; NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to the Company, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows: ARTICLE I. -- Definitions and References (S) 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment. (S) 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this (S) 1.2. "Amendment" means this First Amendment to Fourth Amended and Restated Credit Agreement. "Amendment Documents" means this Amendment. "Credit Agreement" means the Original Agreement as amended hereby. -1- ARTICLE II. -- Amendments (S) 2.1. Definitions. The definitions of "Subsidiary Guarantor" and "Unrestricted Subsidiary" set forth in Section 1.01 of the Original Agreement are hereby amended in their entirety to read as follows: "Subsidiary Guarantor" shall mean each of the following Subsidiaries of the Company: Stocker Resources, L.P., Calumet Florida, Inc., Plains Illinois Inc., Plains Resources International Inc. and Stocker Resources, Inc. "Unrestricted Subsidiary" shall mean each of PAAI, the MLP, All American Pipeline LP and Plains Marketing LP and each of their respective Subsidiaries, whether now existing or hereafter formed or acquired. The definitions of "PMTI" and "PMTI Credit Facility" set forth in Section 1.01 of the Original Agreement are hereby deleted in their entirety. The following definition of "Affiliate Agreements" is hereby added to Section 1.01 of the Original Agreement immediately following the definition of "Affiliate": "Affiliate Agreements" means (i) that certain Crude Oil Marketing Agreement dated as of the Offering Closing Date among the Company, Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing LP, (ii) that certain Omnibus Agreement dated as of the Offering Closing Date among the Company, the MLP, Plains Marketing LP, All American Pipeline LP and PAAI, (iii) that certain Contribution, Conveyance and Assumption Agreement dated as of the Offering Closing Date among the MLP, the Company and certain other parties, and (iv) that certain Underwriting Agreement dated as of November 17, 1998 among the Company, the MLP, All American Pipeline LP, Plains Marketing LP, PAAI and the underwriters party thereto. The following definition of "All American Pipeline LP" is hereby added to Section 1.01 of the Original Agreement immediately following the definition of "Agent": "All American Pipeline LP" means All American Pipeline, L.P., a Texas limited partnership, in which, on the Offering Closing Date, the MLP will own a 99.999% limited partner interest, and PAAI will own a 0.001% general partner interest. The following definitions of "MLP" and "MLP Offering Prospectus" are hereby added to Section 1.01 of the Original Agreement immediately following the definition of "Maximum Rate": "MLP" means Plains All American Pipeline, L.P., a Delaware limited partnership, in which PAAI will own, on the Offering Closing Date, a one percent (1%) general partner interest and (ii) indirectly, a 55.9% (assumes no exercise of underwriters' over-allotment option) limited partner interest. -2- "MLP Offering Prospectus" means that certain Prospectus dated November 17, 1998 regarding the offering by the MLP of common units representing limited partner interests in the MLP. The following definition of "Offering Closing Date" is hereby added to Section 1.01 of the Original Agreement immediately following the definition of "Obligors": "Offering Closing Date" means the date of delivery to the underwriters, and payment for, the common units representing limited partner interests in the MLP, offered pursuant to the initial public offering thereof as described in the MLP Offering Prospectus. The following definition of "Plains Marketing LP" is hereby added to Section 1.01 of the Original Agreement immediately following the definition of "Person": "Plains Marketing LP" means Plains Marketing, L.P., a Delaware limited partnership, in which, on the Offering Closing Date, the MLP will own a 98.9899% limited partner interest, and PAAI will own a 1.0101% general partner interest. (S) 2.2. PMTI Provisions. Sections 8.08(j), 8.08(k) and 8.09(e) of the Original Agreement are hereby deleted in their entirety. Section 8.10(c) of the Original Agreement is hereby amended in its entirety to read as follows: (c) loans, advances and other extensions of credit made after the date hereof by the Company and its Subsidiaries to Subsidiaries of the Company in the ordinary course of business, provided that (i) the aggregate amount of such loans, advances and other extensions of credit by the Company to any one of its Subsidiaries shall not exceed $5,000,000 at any one time outstanding and (ii) the aggregate amount of such loans, advances and other extensions of credit by the Company to its Subsidiaries taken as a whole shall not exceed $5,000,000 at any one time outstanding; in addition to the foregoing, so long as no Default shall have occurred and be continuing or would exist after giving effect thereto, the Company may make Investments without limitation in Stocker Resources, Inc., Stocker Resources, L.P., Calumet Florida Inc. and Plains Illinois Inc. The proviso in the first sentence of Section 8.19 of the Original Agreement is hereby deleted in its entirety. Section 8.29 of the Original Agreement is hereby deleted in its entirety. Section 8.33(a) of the Original Agreement is hereby deleted in its entirety. (S) 2.4. Unrestricted Subsidiaries. Section 8.35 of the Original Agreement is hereby amended in its entirety to read as follows: 8.35 Unrestricted Subsidiaries. Each Unrestricted Subsidiary shall be subject to the following: (a) No Unrestricted Subsidiary shall be deemed to be a "Subsidiary" of the Company for purposes of this Agreement or any other Basic Document, and no -3- Unrestricted Subsidiary shall be subject to or included within the scope of any provision herein or in any other Basic Document, including without limitation any representation, warranty, covenant or Event of Default herein or in any other Basic Document, except as set forth in this Section 8.35. (b) Except as permitted under Section 8.10(e) and (f) and for the indemnity undertakings of the Company and its Subsidiaries party thereto provided for in the Affiliate Agreements, neither the Company nor any of its Subsidiaries shall Guarantee any Indebtedness or other obligation of, grant any Lien on any of its Property to secure any Indebtedness or other obligation of, make any Investment in, assume or grant an indemnity with respect to, or provide any other form of credit support to, any Unrestricted Subsidiary, and neither the Company nor any of its Subsidiaries shall enter into (i) any management contract or agreement with any Unrestricted Subsidiary, except upon the prior written consent of Majority Lenders, not to be unreasonably withheld, or (ii) any other contract or agreement with any Unrestricted Subsidiary, except in the course of ordinary business on terms no less favorable to the Company or such Subsidiary, as applicable, than could be obtained in a comparable arm's length transaction from an unaffiliated party. (S) 2.5. Consent to MLP-related Transactions. In connection with the MLP's proposed offering of common units representing limited partner interests in itself to the public, as set forth in the MLP Offering Prospectus, copies of which have been made available to Agent and Lenders: (a) Agent and Lenders hereby consent to the Company and its Subsidiaries party thereto (i) following the merger of PMTI (as defined in the Original Agreement), Plains Terminal & Transfer Corporation, PLX Crude Lines, Inc. and PLX Ingleside Inc. with and into the Company, with the Company being the surviving entity, selling certain assets held by such merged Subsidiaries prior to such merger to Plains Marketing LP, and (ii) entering into the Affiliate Agreements, copies of which have been made available to Agent and Lenders; and (b) Agent and Lenders hereby waive any Default or Event of Default caused by any of the foregoing or the consummation of any of the other transactions set forth in the MLP Registration Statement. In connection with the foregoing, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Agent and each Lender do hereby release and discharge in full PMTI, Plains Terminal and Transfer Corporation, PLX Crude Lines Inc. and PLX Ingleside Inc. (collectively, the "Released Subsidiary Guarantors") and their respective successors and assigns, from any and all obligations under that certain Amended and Restated Guaranty dated May 2, 1998 by the Released Subsidiary Guarantors, Plains Resources International Inc. and Stocker Resources, Inc. in favor of Agent and Lenders. This is a partial release only and shall not release, discharge or impair any rights, titles, interests, liens, or powers with respect to any other Subsidiary Guarantor existing by virtue of such Guaranty or any other Security Documents, and as to all such other Subsidiary Guarantors, such Guaranty and the other Security Documents shall remain in full force and effect in accordance with their respective terms. -4- ARTICLE III. -- Conditions of Effectiveness (S) 3.1. Effective Date. This Amendment shall become effective as of the date first above written when and only when Agent shall have received, at Agent's office, a counterpart of this Amendment executed and delivered by the Company, Agent and each Lender. ARTICLE IV. -- Representations and Warranties (S) 4.1. Representations and Warranties of the Company. In order to induce Agent and Lenders to enter into this Amendment, the Company represents and warrants to Agent and Lenders that: (a) The representations and warranties contained in Section 7 of the Original Agreement, are true and correct at and as of the time of the effectiveness hereof, subject to the amendment of certain of the Schedules to the Credit Agreement as attached hereto. (b) The Company and the Subsidiaries are duly authorized to execute and deliver this Amendment and the other Amendment Documents to the extent a party thereto, and the Company is and will continue to be duly authorized to borrow and perform its obligations under the Credit Agreement. The Company and the Subsidiaries have duly taken all corporate action necessary to authorize the execution and delivery of this Amendment and the other Amendment Documents, to the extent a party thereto, and to authorize the performance of their respective obligations thereunder. (c) The execution and delivery by the Company and the Subsidiaries of this Amendment and the other Amendment Documents, to the extent a party thereto, the performance by the Company and the Subsidiaries of their respective obligations hereunder and thereunder, and the consummation of the transactions contemplated hereby and thereby, do not and will not conflict with any provision of law, statute, rule or regulation or of the certificate or articles of incorporation and bylaws of the Company or any Subsidiary, or of any material agreement, judgment, license, order or permit applicable to or binding upon the Company or any Subsidiary, or result in the creation of any lien, charge or encumbrance upon any assets or properties of the Company or any Subsidiary, except in favor of Agent for the benefit of Lenders. Except for those which have been duly obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by the Company or any Subsidiary of this Amendment or any other Amendment Document, to the extent a party thereto, or to consummate the transactions contemplated hereby and thereby. (d) When this Amendment and the other Amendment Documents have been duly executed and delivered, each of the Basic Documents, as amended by this Amendment and the other Amendment Documents, will be a legal and binding instrument and agreement of the Company and the Subsidiaries, to the extent a party thereto, enforceable in accordance with its terms, (subject, as to enforcement of remedies, to -5- applicable bankruptcy, insolvency and similar laws applicable to creditors' rights generally and to general principles of equity). ARTICLE V. -- Miscellaneous (S) 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Basic Documents, as they may be amended or affected by this Amendment and/or the other Amendment Documents, are hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Basic Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment and the other Amendment Documents shall not, except as expressly provided herein or therein, operate as a waiver of any right, power or remedy of Agent or any Lender under the Credit Agreement or any other Basic Document nor constitute a waiver of any provision of the Credit Agreement or any other Basic Document. (S) 5.2. Ratification of Security Documents. The Company, Agent and Lenders each acknowledge and agree that any and all indebtedness, liabilities or obligations arising under or in connection with the Notes are Obligations and is secured indebtedness under, and is secured by, each and every Security Document to which the Company is a party. The Company hereby re-pledges, re-grants and re-assigns a security interest in and lien on every asset of the Company described as collateral in any Security Document. (S) 5.3. Survival of Agreements. All representations, warranties, covenants and agreements of the Company herein and in the other Amendment Documents shall survive the execution and delivery of this Amendment and the other Amendment Documents and the performance hereof and thereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by the Company or any Subsidiary hereunder, under the other Amendment Documents or under the Credit Agreement to Agent or any Lender shall be deemed to constitute representations and warranties by, or agreements and covenants of, the Company under this Amendment and under the Credit Agreement. (S) 5.4. Basic Documents. This Amendment and each of the other Amendment Documents is a Basic Document, and all provisions in the Credit Agreement pertaining to Basic Documents apply hereto and thereto. (S) 5.5. GOVERNING LAW. THIS AMENDMENT AND THE OTHER AMENDMENT DOCUMENTS SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE. (S) 5.6. Counterparts. This Amendment and each of the other Amendment Documents may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment or Amendment Document, as the case may be. -6- IN WITNESS WHEREOF, this Amendment is executed as of the date first above written. PLAINS RESOURCES INC. By:/s/ Phillip D. Kramer ---------------------- Phillip D. Kramer Vice President and Chief Financial Officer ING (U.S.) CAPITAL CORPORATION, as Agent and a Lender By: /s/ Christopher R. Wagner --------------------------- Christopher R. Wagner, Senior Vice President BANKBOSTON, N.A., Lender By: /s/ Terrence Ronan --------------------- Terrence Ronan, Vice President DEN NORSKE BANK ASA, Lender By: /s/ Byron L. Cooley ----------------------- Byron L. Cooley, Senior Vice President By: /s/ William V. Moyer ------------------------ William V. Moyer, First Vice President WELLS FARGO BANK (TEXAS), NATIONAL ASSOCIATION, Lender By: /s/ Ann M. Rhoads --------------------- Ann M. Rhoads, Vice President CHASE BANK OF TEXAS, N.A., Lender By: /s/ Russell Johnson ---------------------- Russell Johnson Vice President -7- COMERICA BANK-TEXAS, Lender By: /s/ Daniel P. Tralmer ------------------------- Daniel P. Tralmer, Assistant Vice President MEESPIERSON CAPITAL CORP., Lender By: /s/ Darrell W. Holley ------------------------- Darrell W. Holley, Senior Vice President By: /s/ Karel Louman ------------------- Karel Louman, Managing Director BANK OF SCOTLAND, Lender By: /s/ Annie Chin Tat --------------------- Annie Chin Tat, Senior Vice President U.S. BANK NATIONAL ASSOCIATION, Lender By: /s/ Monte E. Deckerd ------------------------ Monte E. Deckerd, Vice President HIBERNIA NATIONAL BANK By: /s/ Tammy Angelety --------------------- Tammy Angelety Assistant Vice President -8- CONSENT AND AGREEMENT --------------------- Each of the undersigned Subsidiary Guarantors hereby consents to the provisions of this Amendment and the transactions contemplated herein and hereby (i) acknowledges and agrees that any and all indebtedness, liabilities or obligations arising under or in connection with the Notes are Obligations and are secured indebtedness under, and are secured by, each and every Security Document to which it is a party, (ii) re-pledges, re-grants and re-assigns a security interest in and lien on all of its assets described as collateral in any Security Document, (iii) ratifies and confirms its Amended and Restated Guaranty dated May 22, 1998 made by it for the benefit of Agent and Lenders, and (iv) expressly acknowledges and agrees that such Subsidiary Guarantor guarantees all indebtedness, liabilities and obligations arising under or in connection with the Notes pursuant to the terms of such Amended and Restated Guaranty, and agrees that its obligations and covenants thereunder are unimpaired hereby and shall remain in full force and effect. PLAINS RESOURCES INTERNATIONAL INC. STOCKER RESOURCES, INC. CALUMET FLORIDA, INC. PLAINS ILLINOIS INC. By: /s/ Phillip D. Kramer ------------------------- Phillip D. Kramer Vice President and Chief Financial Officer STOCKER RESOURCES, L.P. By: Stocker Resources, Inc., its General Partner By: /s/ Phillip D. Kramer ------------------------- Phillip D. Kramer Vice President and Chief Financial Officer -9- EX-10.N 3 2ND AMENDMENT TO CREDIT AGREEMENT EXHIBIT 10(n) SECOND AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT THIS SECOND AMENDMENT TO FOURTH AMENDED AND RESTATED CREDIT AGREEMENT (this "Amendment") dated as of the 15th day of March, 1999, by and among PLAINS RESOURCES INC., a Delaware corporation (the "Company"), ING (U.S.) CAPITAL LLC, successor in interest to ING (U.S.) CAPITAL CORPORATION, as Agent ("Agent"), and the Lenders under the Original Agreement (as defined herein). W I T N E S S E T H: WHEREAS, the Company, Agent and Lenders entered into that certain Fourth Amended and Restated Credit Agreement dated as of May 22, 1998, as amended by a First Amendment to Fourth Amended and Restated Credit Agreement dated November 17, 1998 (as amended, the "Original Agreement") for the purposes and consideration therein expressed, pursuant to which Lenders became obligated to make and made loans to the Company as therein provided; and WHEREAS, the Company, Agent and Lenders desire to amend the Original Agreement for the purposes described herein; NOW, THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein and in the Original Agreement, in consideration of the loans which may hereafter be made by Lenders to the Company, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto do hereby agree as follows: ARTICLE I. -- Definitions and References (S) 1.1. Terms Defined in the Original Agreement. Unless the context otherwise requires or unless otherwise expressly defined herein, the terms defined in the Original Agreement shall have the same meanings whenever used in this Amendment. (S) 1.2. Other Defined Terms. Unless the context otherwise requires, the following terms when used in this Amendment shall have the meanings assigned to them in this (S) 1.2. "Amendment" means this Second Amendment to Fourth Amended and Restated Credit Agreement. "Amendment Documents" means this Amendment. "Credit Agreement" means the Original Agreement as amended hereby. -1- ARTICLE II. -- Amendments (S) 2.1. Financial Statements. The references to "Consolidated Subsidiaries" in clause (i) of Section 8.01(a) and clause (i) of Section 8.01(b) are hereby amended to refer instead to "Consolidated Subsidiaries and Unrestricted Subsidiaries". (S) 2.2. Investments. Section 8.10(f) of the Original Agreement is hereby amended in its entirety to read as follows: (f) in addition to any capital contributions permitted in subsection (e) above, the following Investments in Unrestricted Subsidiaries: (i) capital contributions of up to $85,000,000 of the proceeds of any preferred or common stock of the Company issued after January 1, 1998 and prior to December 31, 1998, (ii) any Investment represented by, or required to comply with the obligations undertaken under, the Stock Purchase Agreement dated as of March 15, 1998 among the Company, PAAI and Wingfoot Ventures Seven Inc., as amended or modified, made prior to December 31, 1998, and (iii) on or prior to December 31, 1999, an aggregate Investment of up to $40,000,000 in one or more Unrestricted Subsidiaries in connection with their acquisition of, and respective Investments in, Scurlock Permian LLC, a wholly-owned subsidiary of Marathon Ashland Petroleum LLC, which is engaged in crude oil transportation, trading and marketing in an area reaching from the Rocky Mountains through the Gulf Coast. (S) 2.3. Current Ratio. Section 8.13 of the Original Agreement is hereby amended in its entirety to read as follows: 8.13 Current Ratio. The Company will not at any time permit current assets of the Company and its Consolidated Subsidiaries to be less than 100% of current liabilities. For purposes hereof, the terms "current assets" and "current liabilities" shall have the respective meanings assigned to them by GAAP, and, in addition (i) the unused amount of the Borrowing Base plus sixty percent (60%) of the fair market value of any common units of the MLP owned directly or indirectly by the Company shall be included as current assets, and (ii) all LC Obligations shall be included as current liabilities, regardless of whether or not contingent (but without duplication). (S) 2.4. Use of Proceeds. The last sentence of Section 8.17 of the Original Agreement is hereby amended to read as follows: In addition, the Company may use up to $55,000,000 of the proceeds of the Loans hereunder to make or refinance capital contributions to Unrestricted Subsidiaries as permitted in Section 8.10(e) and up to $40,000,000 of the proceeds of the Loans hereunder to make Investments to one or more Unrestricted Subsidiaries as permitted in Section 8.10(f)(iii). ARTICLE III. -- Conditions of Effectiveness (S) 3.1. Effective Date. This Amendment shall become effective as of the date first above written when and only when Agent shall have received, at Agent's office, a counterpart of this Amendment executed and delivered by the Company, Agent and each Lender. -2- ARTICLE IV. -- Representations and Warranties (S) 4.1. Representations and Warranties of the Company. In order to induce Agent and Lenders to enter into this Amendment, the Company represents and warrants to Agent and Lenders that: (a) The representations and warranties contained in Section 7 of the Original Agreement, are true and correct at and as of the time of the effectiveness hereof, subject to the amendment of certain of the Schedules to the Credit Agreement as attached hereto. (b) The Company and the Subsidiaries are duly authorized to execute and deliver this Amendment and the other Amendment Documents to the extent a party thereto, and the Company is and will continue to be duly authorized to borrow and perform its obligations under the Credit Agreement. The Company and the Subsidiaries have duly taken all corporate action necessary to authorize the execution and delivery of this Amendment and the other Amendment Documents, to the extent a party thereto, and to authorize the performance of their respective obligations thereunder. (c) The execution and delivery by the Company and the Subsidiaries of this Amendment and the other Amendment Documents, to the extent a party thereto, the performance by the Company and the Subsidiaries of their respective obligations hereunder and thereunder, and the consummation of the transactions contemplated hereby and thereby, do not and will not conflict with any provision of law, statute, rule or regulation or of the certificate or articles of incorporation and bylaws of the Company or any Subsidiary, or of any material agreement, judgment, license, order or permit applicable to or binding upon the Company or any Subsidiary, or result in the creation of any lien, charge or encumbrance upon any assets or properties of the Company or any Subsidiary, except in favor of Agent for the benefit of Lenders. Except for those which have been duly obtained, no consent, approval, authorization or order of any court or governmental authority or third party is required in connection with the execution and delivery by the Company or any Subsidiary of this Amendment or any other Amendment Document, to the extent a party thereto, or to consummate the transactions contemplated hereby and thereby. (d) When this Amendment and the other Amendment Documents have been duly executed and delivered, each of the Basic Documents, as amended by this Amendment and the other Amendment Documents, will be a legal and binding instrument and agreement of the Company and the Subsidiaries, to the extent a party thereto, enforceable in accordance with its terms, (subject, as to enforcement of remedies, to applicable bankruptcy, insolvency and similar laws applicable to creditors' rights generally and to general principles of equity). ARTICLE V. -- Miscellaneous (S) 5.1. Ratification of Agreements. The Original Agreement, as hereby amended, is hereby ratified and confirmed in all respects. The Basic Documents, as they may be amended or -3- affected by this Amendment and/or the other Amendment Documents, are hereby ratified and confirmed in all respects. Any reference to the Credit Agreement in any Basic Document shall be deemed to refer to this Amendment also. The execution, delivery and effectiveness of this Amendment and the other Amendment Documents shall not, except as expressly provided herein or therein, operate as a waiver of any right, power or remedy of Agent or any Lender under the Credit Agreement or any other Basic Document nor constitute a waiver of any provision of the Credit Agreement or any other Basic Document. (S) 5.2. Ratification of Security Documents. The Company, Agent and Lenders each acknowledge and agree that any and all indebtedness, liabilities or obligations arising under or in connection with the Notes are Obligations and is secured indebtedness under, and is secured by, each and every Security Document to which the Company is a party. The Company hereby re-pledges, re-grants and re-assigns a security interest in and lien on every asset of the Company described as collateral in any Security Document. (S) 5.3. Survival of Agreements. All representations, warranties, covenants and agreements of the Company herein and in the other Amendment Documents shall survive the execution and delivery of this Amendment and the other Amendment Documents and the performance hereof and thereof, including without limitation the making or granting of each Loan, and shall further survive until all of the Obligations are paid in full. All statements and agreements contained in any certificate or instrument delivered by the Company or any Subsidiary hereunder, under the other Amendment Documents or under the Credit Agreement to Agent or any Lender shall be deemed to constitute representations and warranties by, or agreements and covenants of, the Company under this Amendment and under the Credit Agreement. (S) 5.4. Basic Documents. This Amendment and each of the other Amendment Documents is a Basic Document, and all provisions in the Credit Agreement pertaining to Basic Documents apply hereto and thereto. (S) 5.5. GOVERNING LAW. THIS AMENDMENT AND THE OTHER AMENDMENT DOCUMENTS SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND ANY APPLICABLE LAWS OF THE UNITED STATES OF AMERICA IN ALL RESPECTS, INCLUDING CONSTRUCTION, VALIDITY AND PERFORMANCE. (S) 5.6. Counterparts. This Amendment and each of the other Amendment Documents may be separately executed in counterparts and by the different parties hereto in separate counterparts, each of which when so executed shall be deemed to constitute one and the same Amendment or Amendment Document, as the case may be. -4- IN WITNESS WHEREOF, this Amendment is executed as of the date first above written. PLAINS RESOURCES INC. By: /s/ Michael R. Patterson -------------------------------- Michael R. Patterson Vice President and General Counsel -5- ING (U.S.) CAPITAL LLC, as Agent and a Lender By: /s/ Peter Y. Clinton -------------------------------- Name: Peter Y. Clinton Title: Senior Vice President -6- BANKBOSTON, N.A., Lender By: /s/ Terrence Ronan -------------------------------- Terrence Ronan, Vice President -7- DEN NORSKE BANK ASA, Lender By: /s/ J. Morten Kreutz -------------------------------- Name: J. Morten Kreutz Title: Vice President By: /s/ William V. Moyer -------------------------------- Name: William V. Moyer Title: Senior Vice President -8- WELLS FARGO BANK (TEXAS), NATIONAL ASSOCIATION, Lender By: /s/ Ann M. Rhoads -------------------------------- Name: Ann M. Rhoads Title: Vice President -9- CHASE BANK OF TEXAS, N.A., Lender By: /s/ Russell A. Johnson -------------------------------- Name: Russell A. Johnson Title: Vice President -10- COMERICA BANK-TEXAS, Lender By: /s/ Daniel G. Steele -------------------------------- Name: Daniel G. Steele Title: Senior Vice President -11- MEESPIERSON CAPITAL CORP., Lender By: /s/ Darrell W. Holley -------------------------------- Name: Darrell W. Holley Title: Senior Vice President By: /s/ Karel Louman -------------------------------- Name: Karel Louman Title: Managing Director -12- BANK OF SCOTLAND, Lender By: /s/ Annie Chin Tat -------------------------------- Name: Annie Chin Tat Title: Senior Vice President -13- U.S. BANK NATIONAL ASSOCIATION, Lender By: /s/ Monte E. Deckerd -------------------------------- Name: Monte D. Deckerd Title: Vice President -14- HIBERNIA NATIONAL BANK By: /s/ Tammy Angelety -------------------------------- Name: Tammy Angelety Title: Vice President -15- GENERAL ELECTRIC CAPITAL CORPORATION By: /s/ Michael J. Tzougrakis -------------------------------- Name: Michael J. Tzougrakis Title: Manager of Operations -16- CONSENT AND AGREEMENT Each of the undersigned Subsidiary Guarantors hereby consents to the provisions of this Amendment and the transactions contemplated herein and hereby (i) acknowledges and agrees that any and all indebtedness, liabilities or obligations arising under or in connection with the Notes are Obligations and are secured indebtedness under, and are secured by, each and every Security Document to which it is a party, (ii) re-pledges, re-grants and re-assigns a security interest in and lien on all of its assets described as collateral in any Security Document, (iii) ratifies and confirms its Amended and Restated Guaranty dated May 22, 1998 made by it for the benefit of Agent and Lenders, and (iv) expressly acknowledges and agrees that such Subsidiary Guarantor guarantees all indebtedness, liabilities and obligations arising under or in connection with the Notes pursuant to the terms of such Amended and Restated Guaranty, and agrees that its obligations and covenants thereunder are unimpaired hereby and shall remain in full force and effect. PLAINS RESOURCES INTERNATIONAL INC. STOCKER RESOURCES, INC. CALUMET FLORIDA, INC. PLAINS ILLINOIS INC. By: /s/ Michael R. Patterson -------------------------------- Name: Michael R. Patterson Title: Vice President STOCKER RESOURCES, L.P. By: Stocker Resources, Inc., its General Partner By: /s/ Michael R. Patterson -------------------------------- Name: Michael R. Patterson Title: Vice President -17- EX-10.O 4 PEFANIS EMPLOYMENT AGREEMENT EXHIBIT 10(o) EMPLOYMENT AGREEMENT EMPLOYMENT AGREEMENT ("Agreement"), made as of the 23rd day of November, 1998 (the "Effective Date"), between Plains Resources Inc., a Delaware corporation (the "Company"), and Harry N. Pefanis ("Employee"). W I T N E S S E T H: - - - - - - - - - - 1. Employment and Term of Employment. The Company hereby employs the Employee, and the Employee hereby agrees to serve the Company, on the terms and conditions set forth herein. Subject to the provisions of Sections 7 and 8, the term of this Agreement shall be for an initial period of three years from the Effective Date hereof. Not more than 90 days and not less than 60 days prior to the first anniversary of the Effective Date hereof and again during the same period prior to each subsequent anniversary of the Effective Date hereof (each a "Contract Anniversary Date"), the Employee may provide written notice (an "Extension Notice") to the President and Chief Executive Officer of the Company stating that he wishes to extend the remaining term of this Agreement for one year. Unless the Employee receives, prior to the Contract Anniversary Date immediately following delivery of such Extension Notice, a written response from the Chairman of the Board of Directors of the Company (the "Board") (or, if applicable, the Chairman of the Compensation Committee) to the effect that the Board has voted not to extend the remaining term of this Agreement, then the term of this Agreement shall be automatically extended for such one-year period. Failure of the Employee to provide a timely Extension Notice as contemplated by this Section 1 shall automatically cause the term of this Agreement to conclude two years following the Contract Anniversary Date prior to which the Extension Notice would have otherwise been provided. Notwithstanding the foregoing, on the effective date of a "Change in Control of the Company", as defined in Section 7(d), or on the Disposition Date, as defined in Section 7(e), the term of this Agreement automatically shall be extended for three years from such effective date or Disposition Date, as the case may be. 2. Position and Duties. The Employee shall serve as an Executive Vice President of the Company and the President and Chief Operating Officer of Plains All American Inc. ("PAAI"), shall report to the President and Chief Executive Officer of the Company, and shall have supervision and control over and responsibility for (i) the marketing operations of the Company and its subsidiaries, and (ii) the overall operations of PAAI, with such other powers and duties as may from time to time be prescribed by the President and Chief Executive Officer of the Company, provided that such duties are consistent with the Employee's positions. The Employee shall, during the term of this Agreement, devote such of his entire working time, attention, energies and business efforts to his duties and responsibilities hereunder as are reasonably necessary to carry out the duties and responsibilities generally appertaining to such offices, it being agreed that the Employee's principal duties and responsibilities shall be serving as President and Chief Operating Officer of PAAI and that the Company shall not require the Employee to engage in activities that materially detract from the Employee's ability to satisfactorily discharge his duties and responsibilities as President and Chief Operating Officer of PAAI. The Employee shall not, during the term of this Agreement, engage in any other business activity (regardless of whether such business activity is pursued for gain, profit or other pecuniary advantage) without the prior written approval of the President and Chief Executive Officer of the Company (which approval shall not be unreasonably withheld). Nothing in this Section 2 shall be deemed to restrict the Employee from investing his personal assets as a passive investor in the publicly traded securities of other companies. 3. Place of Performance. Subject to such business travel from time to time as may be reasonably required in the discharge of his duties and responsibilities under this Agreement, the Employee shall perform his obligations hereunder at the Company's principal place of business in Houston, Texas. 4. Compensation. (a) Base Salary and Bonus. Subject to the provisions of Section 7 and 8, during the period of the Employee's employment hereunder, the Company shall pay the Employee an aggregate base salary at an annual rate which shall be determined from time to time by the Board or its Compensation Committee. The Employee's initial base salary as of the date hereof, shall be $235,000 per annum. Such initial base salary as the same may be increased from time to time as provided herein shall be hereinafter referred to as the "Base Salary." The Base Salary shall be paid in equal installments pursuant to the Company's customary payroll policies in force at the time of payment (but in no event less frequently than semi-monthly), less required payroll deductions. The Base Salary shall be reviewed in January of each year and may be increased as of each January 1st to reflect the Employee's performance and contribution, such increases, if any, to be in such amounts as the Board or the Compensation Committee shall determine is reasonable. During the term of this Agreement, the Employee's Base Salary shall not be reduced below its then-current rate unless the Board shall implement across-the-board salary reductions for all executive officers of the Company, in which event the Employee's Base Salary shall not, without his consent, be reduced to an amount which is less than the greater of (i) $200,000 or (ii) 85% of the Base Salary in effect immediately prior to such reduction. In addition to Base Salary, the Employee shall be entitled to receive such incentive compensation payments as the Board or its Compensation Committee may determine, including an annual bonus. Factors to be considered in determining the amount of any such bonus will include the Employee's contributions to the Company's upstream activities, the performance of Plains All American Pipeline, L.P. and the correlation of the Employee's bonus to the bonuses paid by PAAI to its other key employees pursuant to its annual incentive programs. (b) Expenses. During the term of his employment hereunder, the Employee shall be entitled to receive prompt reimbursement for all reasonable expenses incurred by him (in accordance with the policies and procedures established by the Company) in performing services hereunder. 2 (c) Fringe Benefits. The Employee shall be entitled to participate in or receive benefits under any pension plan, profit-sharing plan, savings plan, stock option plan, life insurance, health-and-accident plan or arrangement made available by the Company to its executives and key management employees, subject to and on a basis consistent with the terms, conditions, and overall administration of such plans and arrangements. The Employee shall be entitled to prompt payment or reimbursement by the Company for monthly dues and Company- related charges at such social club or clubs as may be approved during the term of this Agreement by the President and Chief Executive Officer of the Company or his delegate. Except for proceeds from key-man life insurance purchased and maintained by the Company, if applicable, for the purpose, among others, of funding its obligations to the Employee or his estate under Section 8, nothing paid to the Employee under any plan or arrangement presently in effect or made available in the future shall be deemed to be in lieu of compensation to the Employee hereunder. (d) Working Facilities. The Company shall furnish the Employee with a private office, secretary and such other facilities and services suitable to his position and adequate for the performance of his duties. (e) Vacations. The Employee shall be entitled to the number of paid vacation days in each calendar year determined by the Company from time to time for its senior executive officers, but not less than 15 business days in any calendar year (prorated in any calendar year during which the Employee is employed hereunder for less than the entire such year in accordance with the number of days in such calendar year during which he is so employed). All such vacation days shall accumulate from calendar year to calendar year during the term of this contract (or any predecessor or successor contracts or arrangements) in the event that the Employee shall be unable to utilize the full allotment to which he may become entitled in any calendar year. The Employee shall also be entitled to all other paid holidays given by the Company to its senior executive officers. 5. Offices. In addition to his duties as set forth hereunder, the Employee agrees to serve without additional compensation, if elected or appointed thereto, in one or more offices or as a director of any of the Company's subsidiaries, provided, however, that the Employee shall not be required to serve as an officer or director of any such subsidiary if such service would expose him to adverse financial consequences. 6. Confidential Information; Non-solicitation. During the period of his employment hereunder and, except as provided below, for the two-year period following the termination of employment, the Employee shall not, without the written consent of the Board or a person authorized thereby, (i) disclose to any person, other than an employee of the Company or PAAI or a person to whom disclosure is reasonably necessary or appropriate in connection with the performance by the Employee of his duties as an executive of the Company and PAAI, any confidential information obtained by him while in the employ of the Company or PAAI with respect to the Company's or PAAI's business, including but not limited to technology, know-how, processes, maps, geological and geophysical data, information regarding any of PAAI's or its affiliates' pipeline terminalling and marketing customers, practices, or operations, and other proprietary information, the disclosure of which he knows or should know will be damaging to the Company or PAAI; provided however, that 3 confidential information shall not include any information known generally to the public (other than as a result of unauthorized disclosure by the Employee), any information of a type not otherwise considered confidential by persons engaged in the same business or a business similar to that conducted by the Company, or any information which the Employee may be required to disclose by any applicable law, order, or judicial or administrative proceeding, (ii) associate in any capacity whatsoever, whether as a promoter, owner, officer, director, employee, partner, lessee, lessor, lender, agent, consultant, broker, commission salesman or otherwise, in any business engaged in the marketing business conducted by the Company or its subsidiaries of a type competitive, directly or indirectly, with the business of the Company or its subsidiaries, other than passive ownership of up to 5% of the outstanding shares of a publicly traded company, or (iii) directly or indirectly, for whatever reason, whether for his own account or for the account of any other person, firm, corporation or other organization solicit, take away, hire, employ or endeavor to employ any person who is an employee of the Company or any of its subsidiaries. Notwithstanding the foregoing, if the Employee is terminated by the Company other than for Cause prior to January 1, 2001, the noncompetition restrictions in clause (ii) above shall terminate on the first anniversary of the Date of Termination. If any portion of this Section 6 shall be invalid or unenforceable, such invalidity or unenforceability shall in no way be deemed or construed to affect in any way the enforceability of any other portion of this Section 6. If any court in which the Company seeks to have the provision of this Section 6 specifically enforced determines that the activities, time or geographic area hereinabove specified are too broad, such court may determine a reasonable activity, time or geographic area. 7. Termination. (a) Death. The Employee's employment hereunder shall terminate upon his death. (b) Disability. If, as a result of the Employee's incapacity due to physical or mental illness, the Employee shall have been absent from his duties hereunder on a full time basis for twelve consecutive months, and, within 30 days after Notice of Termination is given, shall not have returned to the performance of his duties hereunder on a full-time basis, the Company may terminate the Employee's employment hereunder. (c) Cause. The Company may terminate the Employee's employment hereunder for Cause. For the purpose of this Agreement, the Company shall have "Cause" to terminate the Employee's employment hereunder only upon (i) the willful engaging by the Employee in gross misconduct, or (ii) the nonappealable conviction of the Employee of a felony involving moral turpitude. For purposes of this paragraph, no act, or failure to act, on the Employee's part shall be considered "willful" unless done, or omitted to be done, by him not in good faith and without reasonable belief that his act or omission was in the best interests of the Company or PAAI or otherwise likely to result in no material injury thereto. Notwithstanding the foregoing, the Employee shall not be deemed to have been terminated for Cause unless and until there shall have been delivered to the Employee a copy of a resolution, duly adopted by the affirmative vote of the Board at a meeting duly called and held for the purpose (after reasonable notice to the Employee and an opportunity for him, together with his counsel, to be heard before the Board), finding that in the good 4 faith opinion of the Board, the Employee was guilty of conduct set forth above in clause (i) or (ii) and specifying the particulars thereof in detail. (d) Termination by the Employee. The Employee may terminate his employment hereunder (i) for Good Reason, provided that a Notice of Termination shall have been given by the Employee to the Company within 90 days following the occurrence of the event constituting such Good Reason, (ii) if his health should become impaired to an extent that makes the continued performance of his duties hereunder hazardous to his physical or mental health or his life, or (iii) at any time by giving three months' written notice to the Company of his intention to terminate. For purposes of this Agreement, "Good Reason" shall mean the occurrence of any of the following circumstances: (A) any removal of the Employee from, or any failure to re-elect the Employee to, the positions indicated in Section 2 hereof, except in connection with termination of the Employee's employment either for Cause or as provided in Section 7(e), or (B) a reduction in the Employee's rate of Base Salary other than as permitted by Section 4(a), a material reduction in the Employee's fringe benefits, or any other material failure by the Company to comply with Section 4 hereof, or (C) failure of the Company to obtain the express assumption of and the agreement to perform this Agreement by any successor as contemplated in Section 9 hereof. Under certain circumstances set forth in Section 8, if the Employee terminates employment on or following a Change in Control of the Company, he may be entitled to additional benefits. A "Change in Control of the Company" shall conclusively be deemed to have occurred (i) on the date when any person, including any partnership, limited partnership, syndicate or other group deemed a "person" for purposes of Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended, (A) becomes the beneficial owner, directly or indirectly, of shares of the Company's capital stock having 25% or more of the total number of votes that may be cast in the election of directors of the Company and (B) seeks to elect or cause to be elected two or more members of the Board or otherwise exerts or attempts to exert a controlling influence on the management of the Company, or (ii) on the date the individuals who are Directors of the Company on the date hereof constitute less than a majority of the Board unless the election, or the nomination for election by the Company's stockholders, of each new Director has been approved by a majority of the Directors still then in office who are Directors of the Company on the date hereof; provided, however, that a restructuring of the Company as a wholly-owned subsidiary of another corporation in a transaction in which the owners of shares of capital stock of the Company become the owners, in substantially identical proportions, of all or substantially all of the shares of capital stock of such other corporation shall not be deemed to be a "Change in Control of the Company" for purposes of the foregoing clause (ii); and provided further that no "Change in Control of the Company" shall be deemed to have occurred solely as a result of the issuance of the authorized and unissued capital stock of the Company or of any parent of the Company in connection with a financing or acquisition initiated by the Company or such parent. (e) Disposition of Marketing Operations. If a Marketing Operations Disposition (hereinafter defined) is consummated involving the Company's principal marketing subsidiary, currently Plains Marketing & Transportation Inc. and, effective upon the initial public offering of Common Units of Plains All American Pipeline, L.P. ("PAAP"), PAAI (the "Principal Marketing Subsidiary"), and an entity or person other than an entity or person of which more than 50% of the equity interests are owned, directly or indirectly, by the Company (the "Acquirer"), and as a condition 5 to the Marketing Operations Disposition, the Acquirer requires that the Employee be employed exclusively by the Acquirer or an affiliate of the Acquirer, the Employee's termination of employment with the Company on the date of consummation of the Marketing Operations Disposition (the "Disposition Date") shall not entitle the Employee to any further payments or benefits from the Company pursuant to this Agreement, provided the Acquirer expressly assumes this Agreement pursuant to Section 9 hereof on the Disposition Date "as if" it were a successor to the Company and all obligations of the Company hereunder. Notwithstanding anything in this Agreement to the contrary, a removal of the Employee from, or failure to re-elect the Employee to, the positions indicated in Section 2 hereof on or in connection with a Marketing Operations Disposition and the assumption of this Agreement by the Acquirer shall not constitute a Good Reason event provided the Employee's status, responsibilities and duties, including reporting responsibilities, with the Acquirer and its affiliate, if applicable, are substantially comparable to those positions indicated in Section 2. As used herein, "Marketing Operations Disposition" shall mean (i) the sale or transfer of 50% or more of the capital stock of the Principal Marketing Subsidiary, (ii) a merger or consolidation of the Principal Marketing Subsidiary, (iii) the sale or transfer of all or substantially all of the assets of the Principal Marketing Subsidiary or of PAAP, or (iv) the Principal Marketing Subsidiary and any other 50% or more owned entity of the Company ceasing to be the general partner of PAAP. If the Acquirer either does not require the Employee to be employed exclusively by the Acquirer or an affiliate of the Acquirer, or it fails to assume this Agreement on the Disposition Date as provided above, a termination of the Employee's employment on or within one year following the Disposition Date either by the Company, other than pursuant to Sections 7(a), 7(b) or 7(c), or by the Employee for a Good Reason shall be deemed a termination pursuant to this Section 7(e). (f) Notice of Termination. Any termination by the Company pursuant to subsection (b) or (c) above or by the Employee pursuant to subsection (d) or (e) above shall be communicated by written Notice of Termination to the other party hereto. For purposes of the Agreement, a "Notice of Termination" shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Employee's employment under the provision so indicated. (g) Date of Termination. The "Date of Termination" shall mean (i) if the Employee's employment is terminated by his death, the date of his death, (ii) if the Employee's employment is terminated pursuant to subsection (b) above, 30 days after Notice of Termination is given (provided that the Employee shall not have returned to the performance of his duties on a full-time basis during such 30-day period), (iii) if the Employee's employment is terminated pursuant to subsection (c) or (d)(iii) above, the date specified in the Notice of Termination, (iv) if the Employee's employment is terminated pursuant to subsection (e) above, the Disposition Date, and (v) if the Employee's employment is terminated for any other reason, the date on which a Notice of Termination is given. 6 8. Compensation Upon Termination or During Disability. (a) If the Employee's employment shall be terminated by reason of his death, the Company shall pay to such person as the Employee shall designate in a notice filed with the Company, or, if no such person shall be designated, to his estate as a lump sum death benefit, an amount equal to the highest annual rate at which his Base Salary hereunder was paid prior to the date of death, multiplied by the lesser of (i) two years or (ii) the number of days remaining in the term of this Agreement as provided in Section 1 divided by 360 days per year. So long as the Employee is employed hereunder, subject to availability at a cost which does not reflect any abnormal health or other risks, the Company may purchase and maintain insurance on the life of the Employee with death benefits thereunder payable to the Employee's designated beneficiary or estate which are at least equal to the death benefit provided for in the preceding sentence. Such death benefit shall be exclusive of and in addition to any payments the Employee's widow, beneficiaries or estate may be entitled to receive pursuant to any pension or employee benefit plan maintained by the Company for its executive officers generally. (b) During any period that the Employee fails to perform his duties hereunder as a result of incapacity due to physical or mental illness, the Employee shall continue to receive his full Base Salary at the rate in effect prior to the date of such incapacity until the Date of Termination if the Employee's employment is terminated pursuant to Section 7(b) hereof. (c) If the Employee's employment shall be terminated for Cause as provided in Section 7(c) hereof, the Company shall pay the Employee his full Base Salary through the Date of Termination at the rate in effect at the time Notice of Termination is given and the Company shall have no further payment obligations to the Employee under this Agreement. (d) If the Company shall terminate the Employee's employment other than pursuant to Sections 7(a), 7(b), 7(c) or 7(e) hereof or if the Employee shall terminate his employment pursuant to Section 7(d)(i) or 7(d)(ii) hereof, then (i) the Company shall pay the Employee his full Base Salary plus any accumulated vacation pay through the Date of Termination at the rate in effect at the time Notice of Termination is given; and (ii) in lieu of any further payments to the Employee for periods subsequent to the Date of Termination, the Company shall make a severance payment to the Employee not later than the tenth business day following the Date of Termination, in a lump sum amount equal to the highest annual rate at which his Base Salary hereunder was paid prior to the Date of Termination multiplied by the lesser of (A) two years or (B) the number of days remaining in the term of this Agreement as provided in Section 1 divided by 360 days per year; provided, however, that if the Employee shall terminate his employment pursuant to Section 7(d)(i) on or within one year following a Change in Control of the Company, then such lump sum amount shall equal three times the aggregate of (x) the highest annual rate at which the Employee's Base Salary was paid prior to Date 7 of Termination plus (y) the highest amount of any annual bonus paid to the Employee during the three years prior to the Date of Termination. The Employee shall not be required to mitigate the amount of any payment provided for in this Section 8 by seeking other employment or otherwise. (e) If the Employee terminates this Agreement pursuant to Section 7(d)(iii) hereof, the Employee shall receive his full Base Salary through the Date of Termination including any accrued vacation days at the rate then in effect and the Company shall have no further payment obligations to the Employee under this Agreement. (f) If the Employee's employment with the Company is terminated pursuant to Section 7(e), then the Company shall make a severance payment to the Employee not later than the tenth business day following the Date of Termination in a lump sum amount equal to three times the aggregate of (x) the highest annual rate at which the Employee's Base Salary was paid prior to Date of Termination plus (y) the highest amount of any annual bonus paid to the Employee during the three years prior to the Date of Termination. (g) Unless the Employee is terminated for Cause or the Employee's employment is terminated pursuant to Section 7(a) or 7(d)(iii) hereof, the Employee shall be entitled to continue to participate, for a period which is the lesser of two years from the Date of Termination or the remaining term of this Agreement, in such health and accident plan or arrangement as is made available by the Company to its executive officers generally. The Employee shall not be entitled to participate in any other employee benefit plan or arrangement of the Company following the Date of Termination except as expressly provided by the terms of any such plan. (h) The Company will reimburse the Employee for the federal excise tax, if any, which is due pursuant to Section 4999 of the Internal Revenue Code of 1986, as amended, on the compensation payments (but not this reimbursement payment) described in this Agreement. 9. Successors; Binding Agreement. (a) The Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company, by agreement in form and substance reasonably satisfactory to the Employee, to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place. Failure of the Company to obtain such agreement prior to the effectiveness of any such succession shall be a breach of this Agreement and shall entitle the Employee to compensation from the Company in the same amount and on the same terms as he would be entitled to hereunder if he had terminated his employment for Good Reason, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Date of Termination. As used in this Agreement, "Company" shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid, and shall also include any Acquirer as defined in Section 7(e), 8 which executes and delivers the agreement provided for in this Section 9 (or Section 7(e), if applicable) or which otherwise becomes bound by all the terms and provisions of this Agreement by operation of law. (b) This Agreement and all rights of the Employee hereunder shall inure to the benefit of and be enforceable by the Employee's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Employee should die while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the Employee's devisee, legatee, or other designee or, if there be no such designee, to the Employee's estate. 10. Indemnification. The Company shall, to the fullest extent permitted by law, indemnify and hold harmless the Employee against any loss, liability, claim, damage and expense, including the cost of defense, incurred in the course of the Employee's employment hereunder. The Company's liability hereunder shall be reduced by the amount of insurance proceeds paid to or on behalf of the Employee with respect to an event giving rise to indemnification hereunder. This indemnification shall survive the death or other termination of employment of the Employee and the termination of this Agreement. Any legal fees incurred by the Employee in the enforcement of this or any other provision of this Agreement shall be promptly reimbursed by the Company as the same are incurred. 11. Survival. The provisions of Sections 6, 8, and 10 shall survive the termination of employment of the Employee. In addition, all obligations of the Company to make payments hereunder shall survive any termination of this Agreement. 12. Notice. For the purpose of this Agreement, notices and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the parties at their addresses set forth below, or to such other addresses as either party may have furnished to the other in writing in accordance herewith except that notices of change of address shall be effective only upon receipt. If to the Company: Plains Resources Inc. 500 Dallas Street, Suite 700 Houston, Texas 77002 Attention: General Counsel If to the Employee: Harry N. Pefanis 4103 University Blvd. Houston, Texas 77005 9 13. Miscellaneous. No provisions of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Texas. 14. Entire Agreement. This Agreement contains the entire understanding of the parties in respect of its subject matter and supersedes all prior oral and written agreements and understandings between the parties with respect to such subject matter and supersedes all subsequent agreements or understandings between the parties with respect to all employee benefit plans or arrangements in effect on the date hereof or hereafter adopted to the extent that such plans or arrangements conflict with the terms of this Agreement. 15. Validity. The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity or enforceability of any provision of this Agreement, which shall remain in full force and effect. 16. Headings. The headings contained in this Agreement are for reference purposes only and shall not affect the meaning or interpretation of this Agreement. 10 IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first above written. PLAINS RESOURCES INC. By: /s/ John H. Lollar ------------------- Chairman of the Compensation Committee of the Board of Directors HARRY N. PEFANIS /s/ Harry N. Pefanis -------------------- Employee 11 EX-21 5 SUBSIDIARIES OF PLAINS RESOURCES INC. Exhibit 21 SUBSIDIARIES OF PLAINS RESOURCES INC. . Calumet Florida, Inc. . Plains Illinois Inc. . Stocker Resources, Inc. . Stocker Resources, L.P. . Plains Resources International Inc. . PMCT INC. . Plains All American Inc. . Plains All American Pipeline, L.P. . Plains Marketing, L.P. . All American Pipeline, L.P. . PAAI LLC EX-23.A 6 CONSENT OF PRICEWATERHOUSECOOPERS Exhibit 23.(a) CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in each Prospectus constituting part of the Registration Statements on Form S-3 (Nos. 333-80364, 333-01851, 33-84064, 333-42773, 333-42767, 333-65939) and in each of the Registration Statements on Form S-8 (Nos. 33-43788, 33-48610, 33-53802, 33-06191, 333-27907) of Plains Resources Inc. of our report dated March 29, 1999 appearing on page F-2 of the Annual Report on Form 10-K for the year ended December 31, 1998. PricewaterhouseCoopers LLP Houston, Texas March 29, 1999 EX-27 7 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1998, AND CONSOLIDATED STATEMENT OF INCOME FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998. 1,000 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 6,544 0 128,875 0 42,520 179,466 1,037,608 375,882 974,267 193,407 431,983 88,487 21,946 1,688 49,328 974,267 1,232,443 1,294,092 1,142,155 1,347,049 0 0 35,730 (99,465) (42,720) (58,554) 0 0 0 (58,554) (3.77) (3.77)
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