ITEM 1. BUSINESS
Plains Resources Inc. (the "Company") is an independent energy company engaged in the acquisition, exploitation, development, exploration and production of crude oil and natural gas and the 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") and the Arroyo Grande 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 marketing, terminalling and storage activities are concentrated in Oklahoma, Texas, the Gulf Coast area of Louisiana and California. The Company's upstream operations contributed approximately 87% of the Company's earnings before interest, taxes, depreciation, depletion and amortization ("EBITDA") for the fiscal year ending December 31, 1997, while the Company's midstream activities accounted for the remainder. 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"). The Company's midstream operations are conducted through various wholly owned subsidiaries (referred to collectively as "Plains Marketing"). References to the Company in this Annual Report on Form 10-K (the "Report") include Plains Resources Inc. and its subsidiaries, except as the context may otherwise require./1/
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 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 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 which 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 also seeks to capitalize on midstream opportunities that exist as a result of inefficiencies within the crude oil markets and the U.S. pipeline and transportation infrastructure. On March 21, 1998, Plains All American Inc. ("Plains All American"), a wholly owned subsidiary of the Company, entered into a definitive agreement to acquire 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 The Goodyear Tire & Rubber Company ("Goodyear"). Aggregate proceeds to Goodyear through closing are estimated at $420 million. The transaction is expected to be completed in
- ------------ /(1)/ As used in this Report, "Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl" 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.
the third quarter after regulatory approvals have been secured. See "Business-- All American Pipeline Acquisition". The Company's marketing of its own crude oil production takes advantage of the marketing expertise attributable to its midstream activities.
During the five-year period ended December 31, 1997, the Company incurred aggregate acquisition, exploitation, development, and exploration costs of approximately $365.3 million, resulting in proved oil and natural gas reserve additions (including revisions of estimates but excluding production) of approximately 154.3 million BOE, or $2.37 per BOE, through implementation of its business strategy. See Item 2, "Properties--Oil and Natural Gas Reserves". Approximately 94% of these expenditures were directed toward the acquisition, exploitation and development of proved reserves while approximately 6% were incurred on exploration activities.
In order to manage its exposure to commodity price risk, the Company routinely hedges a portion of its crude oil production. For 1998, the Company has entered into various fixed price and floating price collar arrangements. Such arrangements generally provide the Company with downside price protection on approximately 12,250 barrels of oil per day at a NYMEX crude oil spot price ("NYMEX Crude Oil Price") of approximately $19.80 per barrel. Thus, based on the Company's average fourth quarter 1997 crude oil production rate, these arrangements generally provide the Company with downside price protection for approximately 60% of its crude oil production. In addition, the Company also has fixed price arrangements on 6,000 barrels per day in 1999 at a NYMEX Crude Oil Price of $18.55 per barrel, or approximately 30% of fourth quarter 1997 crude oil production levels. During the first quarter of 1998, the NYMEX Crude Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was approximately $16.50 per barrel.
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. See Item 2, "Properties--Oil and Natural Gas Reserves" and Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations".
- ----------- (1) A large portion of the Company's reserve base (approximately 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. By comparison, calculating these amounts using the NYMEX Crude Oil Price in effect at December 31, 1995, of $19.55 per barrel, results in a Present Value of Proved Reserves of $633 million and $452 million and estimated net proved reserves of 168 million BOE and 112 million BOE at December 31, 1997 and 1996, respectively. 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 year's production. (3) 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. (4) 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. (5) 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 in an effort 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 which could have an adverse impact on exploitation opportunities. If the Company is successful in purchasing 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, 1997, net additions and revisions to proved reserves totaled 73.5 million BOE or approximately 269% of cumulative net production for such period. Such reserves were added at an aggregate average cost of $2.92 per BOE. 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 80.8 million BOE and were added at an aggregate average cost of $1.86 per BOE.
The Company's properties in its three core areas represent approximately 99% of total proved reserves at December 31, 1997. 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 1998, the Company estimates it will spend approximately $91 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. Prior to its acquisition by the Company 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, 1997, the LA Basin Properties have produced over 420 MMBbls of oil and 360 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 10,640 BOE per day during the fourth quarter of 1997.
The Company has expended approximately $110.7 million in direct acquisition, development and exploitation capital on the LA Basin Properties. From the effective dates of acquisition through December 31, 1997, net production from such properties totaled 18.2 million BOE, generating cumulative net margin (oil and natural gas revenue less production expenses) and proceeds from minor property sales of approximately $141.9 million. Total estimated proved reserves attributable to the LA Basin Properties have increased from 17.7 million BOE at initial acquisition to approximately 76.6 million BOE at December 31, 1997. As a result, the Company's aggregate reserve addition cost to date for the LA Basin Properties is approximately $1.17 per BOE. During 1997, the unit gross margin for this area averaged $8.83 per BOE. Estimated future net revenues and the Present Value of Proved Reserves at December 31, 1997, were estimated at $649.4 million and $300.6 million, respectively. The Company estimates it will spend approximately $47 million during 1998 on the further development and exploitation of the LA Basin Properties.
During 1997, the Company expanded its operations in the LA Basin with the acquisition of the Montebello Field (the "Montebello Acquisition"), and expanded into another California area with the acquisition of the Arroyo Grande Field (the "Arroyo Grande Acquisition"). Combined, these two fields added approximately 43 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. At the acquisition date, the field was producing approximately 800 barrels of oil and 800 Mcf of natural gas per day and added approximately 23 MMBbls of oil equivalent to the Company's proved reserves.
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 10 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 degree 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.
As with its other California properties, the Company intends to aggressively exploit the properties acquired in 1997 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. During 1998, the Company estimates that it will spend approximately $17 million on the development and exploitation of the Montebello and Arroyo Grande fields.
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 92 MMBls of oil through December 31, 1997. 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 5,430 barrels of oil per day during the fourth quarter of 1997.
The Company has expended approximately $68.7 million in direct acquisition, development and exploitation capital on the Sunniland Trend Properties. From the effective dates of acquisition through December 31, 1997, net production from such properties totaled 6.3 MMBbl, generating cumulative net margin of approximately $46.6 million. Total estimated proved reserves attributable to the Sunniland Trend Properties have increased from approximately 5.0 MMBbls at initial acquisition to approximately 22.2 MMBbls at December 31, 1997. As a result, the Company's aggregate reserve addition cost to date for the Sunniland Trend Properties is approximately $2.41 per BOE. During
1997, the unit gross margin for this area averaged $7.62 per BOE. At December 31, 1997, estimated future net revenues and the Present Value of Proved Reserves were estimated at $86.8 million and $68.6 million, respectively. During 1998, the Company estimates it will spend approximately $18 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 1998. 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 MMBls 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 410 MMBls of oil through December 31, 1997.
The Company has expended approximately $68.8 million in direct acquisition, development and exploitation capital on the Illinois Basin Properties. From the effective date of acquisition through December 31, 1997, net production from such properties totaled 2.8 MMBls, generating cumulative net margin of approximately $28.2 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 $8.56 per BOE during 1997. As a result of these operating expense reductions, reduced location price differentials and higher average oil prices, this area's unit gross margin increased to $10.60 per BOE during 1997 as compared to $5.37 per BOE at the time of acquisition. Total estimated proved reserves attributable to the Illinois Basin Properties have increased from 17.3 MMBbls at initial acquisition to approximately 20.6 MMBbls at December 31, 1997. As a result, the Company's aggregate reserve addition cost to date for the Illinois Basin Properties is approximately $2.94 per BOE. Estimated future net revenues and the Present Value of Proved Reserves at December 31, 1997, were estimated at $141.8 million and $73.2 million, respectively. The Company intends to aggressively exploit these properties to evaluate additional reserve potential identified during its acquisition analysis. During 1998, the Company estimates it will spend approximately $9 million implementing its exploitation plan on the Illinois Basin Properties. The primary focus of such development and exploitation program during 1998 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 available as a result of sales of domestic oil properties by both major and independent oil companies. While the Company is continually evaluating acquisition 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.
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.
In 1996, the Company and 3DX Technologies Inc. ("3DX") formed a joint venture to pursue the Company's existing exploration projects and a five-year strategic alliance to jointly pursue new exploration and exploitation opportunities that are candidates for the application of 3-D seismic technology. The joint venture covers exploration activities in the Sunniland Trend and the Gulf Coast areas of Texas and Louisiana. 3DX bears principal responsibility for the geological and geophysical oversight and project technical management of such projects. In connection with the joint venture, 3DX acquired 8% to 20% of the Company's working interests in certain projects. 3DX will have certain rights to participate for up to 20% in the Company's new exploration and exploitation projects in these areas.
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 and its partners are 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. 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. Such activities include acquiring a specified amount of 2-D and 3-D seismic data across leads and prospects and drilling a minimum number of wells.
Portions of the acreage will be subject to existing joint ventures and alliances with certain industry participants, including 3DX, which will perform the geophysical and geological analyses with regard to the Exploration Agreement. Prior to the signing of the Exploration Agreement, the Company held leasehold interests in approximately 132,000 gross acres.
Preliminary plans for 1998 include gathering 2-D and/or 3-D seismic data over various prospects and leads and drilling one exploratory well in a new prospect.
General. During 1998, the Company estimates it will spend approximately $6 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 potentially have a higher financial return. During 1997, 1996 and 1995, the Company sold nonstrategic oil and natural gas properties located primarily in the Gulf Coast areas of Texas and Louisiana and in Utah for proceeds of $2.7 million, $3.1 million and $7.4 million, respectively. As a result, approximately 99% of the Company's 1997 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 include two distinguishable but interrelated business activities. Such activities are (i) crude oil gathering and marketing and (ii) crude oil terminalling, storage, blending and exchange. The Company's midstream activities have expanded significantly, with midstream gross margin (revenues less direct expenses of purchases, transportation, storage and terminalling) having increased approximately 635% from $1.7 million in 1992 to $12.5 million in 1997.
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, to major crude oil trading locations for ultimate consumption by refineries and other end markets (the "Distribution Chain"). The Company'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 for aggregation and subsequent resale at various points along the crude oil Distribution Chain. In most cases, the Company performs a merchant function generating profit 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 at favorable prices. The Company aggregates purchased volumes with its own production at major crude oil interchanges and trading locations, which enables it to obtain higher prices for its own production while realizing profits on the production purchased from others. Except for crude oil purchased from time to time as inventory to service the needs of its terminalling and storage customers, the Company's policy is 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 crude oil marketing business is characterized by a large volume of transactions with low margins. The Company has generally maintained a gross margin of approximately 2% in its marketing activities for each of the years 1993 through 1997. The Company also routinely analyzes opportunities for possible purchase or construction of gathering and pipeline systems, processing and storage facilities and various other related capital investment projects to enhance its profitability in the markets in which it operates.
The Company owns and operates a two million barrel, above-ground crude oil storage and terminalling facility in Cushing, Oklahoma (the "Cushing Terminal"). The Company utilizes the Cushing Terminal to provide storage and terminalling services for its own account and for third parties on a negotiated basis and to serve as an aggregation, terminalling and distribution point for establishing and maintaining markets for up to 24 different varieties of foreign and domestic crude oils. The Company estimates that approximately 60% to 70% of the tankage capacity available at the Cushing Terminal was used in 1997; accordingly, substantial additional capacity is available without the expenditure of additional capital. The Company recently received regulatory approval to construct an additional one million barrels of tank capacity at the Cushing Terminal and is formulating its plans with respect thereto. Because of its initial investment in land, engineering and environmental studies, pipeline interconnects and the manifold and pumping system, the cost to construct incremental storage capacity is estimated at $10.00 per barrel of shell capacity. In addition, the Company owns a 360,000 barrel terminal and dock facility located in Ingleside, Texas, just north of the Port of Corpus Christi (the "Ingleside Terminal"). Approximately 60% of the Ingleside Terminal's storage capacity is committed to a lease agreement with five years remaining on the term and the remaining 40% is used to support the Company's crude oil purchasing activities. The Company acquired the Ingleside Terminal in early 1996.
The Cushing Terminal was completed in December 1993. The facility was designed to accommodate the numerous grades of crude oil used by refiners and consists of two million barrels (fourteen 100,000 barrel tanks and four 150,000 barrel tanks) of above-ground shell storage capacity. The Company's total capital investment in the Cushing Terminal through December 31, 1997, was approximately $31.1 million, which includes the cost of land acquisition, engineering and environmental studies, construction-phase interest, pipeline interconnects and an oversized manifold and pumping system that was designed and constructed to accommodate expansion up to an aggregate ten million barrels of storage capacity. The Company estimates that its storage tanks have a useful life in excess of 60 years. The facility is connected to major pipelines into and out of the Cushing interchange and can operate at a daily throughput rate of approximately 800,000 Bbls.
Cushing is the largest wet barrel trading hub in the United States 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. The Cushing Terminal was constructed primarily to capitalize on the crude oil supply and demand imbalance in the Midwest caused by the continued decline of traditional regional supplies, increasing imports and an inadequate pipeline and terminal infrastructure. Based upon the Company's analysis of existing storage facilities at Cushing and the anticipated increase in crude oil volumes to be transported through Cushing, the Company believes that there will be an increasing demand for additional storage capacity at Cushing; however, there can be no assurance that such demand will increase. The Company generates revenue from the Cushing Terminal through a combination of storage, reservation and throughput fees from (i) refiners and gatherers seeking to segregate or custom blend crudes for refining feedstocks, (ii) pipelines, refiners and traders requiring segregated tankage for foreign cargoes, (iii) traders who make or take delivery under the NYMEX contract, and (iv) producers seeking to increase their marketing alternatives and arbitrage opportunities entered into for the Company's own account in contango market crude oil trading activities. The storage and terminal business is generally counter-cyclical to the marketing business insofar as the demand for storage opportunities is higher and the Company's ability to capture profits from arbitrage opportunities existing in the market is enhanced in a contango market as opposed to a market in backwardation. Conversely, marketing margins are typically stronger in a backward market. A contango crude oil futures market exists when the futures price of a subsequent month exceeds the price of a prior month, whereas a market is in backwardization when the opposite condition exists. Such market allows the Company to simultaneously purchase and sell crude oil and lock-in a profit. Because of its designation as an official NYMEX delivery point and its physical capacity to receive, store and redeliver crude oil, the Cushing Terminal provides the optimal mechanism to capitalize on a contango market.
ALL AMERICAN PIPELINE ACQUISITION
On March 21, 1998, Plains All American, a wholly owned subsidiary of the Company, entered into a definitive agreement to acquire all of the outstanding capital stock of the Celeron Companies from Goodyear. Aggregate proceeds to Goodyear through closing are estimated at $420 million. The principal assets of the entities to be 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. The purchase price is subject to certain adjustments through the closing date, and the transaction is subject to regulatory review and approval by the United States Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Anti-Trust Improvements Act of 1976, as amended, and by the Public Utilities Commission of the State of California. The transaction is expected to be completed in the third quarter of 1998 after regulatory approvals have been secured.
A major portion of the financing for the transaction will be provided through a $325 million, limited recourse bank facility made available to Plains All American by ING Barings and BankBoston. In addition to the bank facility, the Company will make a capital contribution to Plains All American of up to $130 million, which will be used to fund the balance of the purchase price and transaction costs and provide initial working capital. To finance its capital contribution, the Company will borrow approximately $50 million under its existing revolving bank facility and has entered into financing commitments for a new issue of privately placed, convertible preferred stock aggregating approximately $80 million. Commitments for the preferred stock placement have been obtained from a group of equity investors comprised primarily of existing shareholders. The preferred stock has an aggregate stated value of $80 million and bears a cumulative dividend of 9.5% per annum, payable semi-annually in either cash or additional shares of
preferred stock at the Company's option. Each share of preferred stock is convertible into 27.78 shares of Common Stock (an 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 preferred stock is redeemable at the option of the Company at 110% of stated value after March 31, 1999, and at declining amounts thereafter. If not previously redeemed or converted, the preferred stock is required to be redeemed in 2012.
The All American Pipeline is the single largest crude oil pipeline connecting California to West Texas, where it connects with pipelines that transport crude oil to Cushing, Oklahoma and the Gulf Coast. The 45-mile gathering system is located in the San Joaquin Valley, currently the most prolific crude oil producing region in the continental United States. The areas serviced by the pipeline and gathering system currently produce over 700,000 barrels of crude oil per day, representing approximately 15% of total oil production in the continental United States. For 1997, the operations to be acquired generated approximately $65 million in EBITDA.
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, 1997, 1996 and 1995:
- ------------ (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 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. Prior to March 30, 1998, the Company's executive offices were located at 1600 Smith Street, Suite 1500, Houston, Texas 77002.
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. A large portion of the Company's reserve base (approximately 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price received by the Company at December 31, 1997, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $18.34 per barrel. During the first quarter of 1998, the NYMEX Crude Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was approximately $16.50 per barrel. 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".
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 Plains Marketing. 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 intends to spend approximately $2.5 million during 1998 and 1999 to improve 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, 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 Federal Energy Regulatory Commission ("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 Koch Oil Company ("Koch") and Sempra Energy Trading Corporation (formerly AIG Trading Corporation) accounted for 27% and 11%, respectively, of the Company's total revenue (exclusive of interest and other income) during 1997. Customers accounting for more than 10% of total revenue for 1996 and 1995 were as follows: 1996 -- Koch - 16% and Basis Petroleum, Inc. ("Basis", formerly Phibro Energy USA, Inc.) - 11%; 1995 -- Phibro Inc. ("Phibro") - 16% and Basis - 12%. No other single customer accounted for as much as 10% of total sales during 1997, 1996 or 1995. Additionally during 1997, Unocal Energy Trading Inc. ("Unocal"), Marathon Oil Company and Exxon accounted for approximately 52%, 23% and 10%, respectively, of the Company's oil and gas sales. During 1997, Unocal and Marathon Oil Company purchased the crude oil from the LA Basin Properties and the Illinois Basin Properties, respectively. See Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations".
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 be dependent upon 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 Company faces intense competition in purchasing and marketing crude oil and in the crude oil storage business. Its competitors include 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 the Company's and control substantially greater supplies of crude oil. Although the Company believes that the environmental safeguards and operating capabilities of the Cushing Terminal are superior to other existing facilities in Cushing, the Company competes with larger companies that possess superior financial resources and have an established business presence. Such advantages could inhibit the development of the Company's business for the Cushing Terminal.
REGULATION
The Company's operations are subject to extensive and continually changing regulation, as legislation affecting the oil and natural gas industry is under constant review 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 are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.
Commodities Regulation
The Company's hedging activities operations 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.
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
The Company's crude oil pipelines and natural gas gathering pipelines are subject to construction, installation, operating and safety regulation by the DOT and various other federal, state and local agencies. The Pipeline Safety Act of 1992, among other things, amends the Hazardous Liquid Pipeline Safety Act of 1979 ("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 and natural gas pipelines. 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 from regulating pipeline safety by federal law 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. The Company 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
Sales of crude oil and condensate can be made by the Company at market prices not subject at this time to price controls. However, the price that the Company receives from the sale of these products is affected by the cost of transporting the products to market. Commencing in October 1993, the FERC issued a series of orders (Order No. 561 and 561-A) in which it revised its regulations governing the rates that may be charged by oil pipelines. The new rules,
which became effective January 1, 1995, provide a simplified, generally applicable method for regulating such rates by use of an index for setting rate ceilings. In certain circumstances, the new rules permit oil pipelines to establish rates using traditional cost of service and other methods of ratemaking. These rules could increase the cost of transporting crude oil and condensate by pipeline. On October 28, 1994, the FERC issued two separate Orders (No. 571 and 572), which adopt additional regulations governing rates that an oil pipeline may be authorized to charge. Order No. 571 authorizes a pipeline to implement cost-of-service based rates, provided it can demonstrate that there is a substantial divergence between the actual costs experienced by the carrier and the indexed rate that the pipeline is directed to charge under Order No. 561. In Order No. 572, the FERC adopted regulations that authorize a pipeline to charge market-based rates, provided it can demonstrate that it lacks significant market power in the market(s) in which it proposes to charge such rates. These rules have been affirmed by the reviewing courts.
Transportation and Sale of Natural Gas
Prior to January 1, 1993, various aspects of the Company's natural gas operations were subject to regulation by the FERC under the Natural Gas Act of 1938 (the "NGA") and the NGPA with respect to "first sales" of natural gas, including price controls and certificate and abandonment authority regulations. However, as a result of the enactment of the Decontrol Act, the remaining "first sales" restrictions imposed by the NGA and the NGPA terminated on January 1, 1993.
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 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.
A significant portion of the Miami Fee acreage in Cameron Parish, Louisiana, is within the Sabine National Wildlife Refuge (the "Refuge"), and operations therein are subject to the National Wildlife Refuge Administration Act and the regulations promulgated thereunder (the "Wildlife Refuge Act"). The Wildlife Refuge Act states that no person may use, occupy, conduct any activity on or remove property from any area located within a wildlife refuge unless a permit has been granted for such use, occupation, conduct, activity or removal of property. The Company has plugged and abandoned the wells drilled on its Miami Fee acreage in prior years and is currently completing the requirements established by the Regional Director of the Refuge.
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 13 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 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.
FEDERAL TAXATION
At December 31, 1997, the Company and its subsidiaries, which together file a consolidated federal income tax return, had federal income tax net operating loss ("NOL") carryforwards of approximately $172 million. Of that amount, approximately $12 million is subject to separate return limitation year restrictions and may only be utilized to the extent certain subsidiaries which generated the NOL's have taxable income. At December 31, 1997, the Company had approximately $159 million of alternative minimum tax ("AMT") net operating loss carryforwards available as a deduction against future AMT income. In addition, the Company had approximately $.5 million of investment tax credit carryforwards and $7 million of percentage depletion carryforwards at December 31, 1997. The NOL carryforwards expire from 1998 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 NOL's.
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, 1997, or will occur as a result of the issuance of the preferred stock in connection with the acquisition of the Celeron Companies. See Item 1, "Business--All American Pipeline Acquisition". 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 NOL's.
In the event of an Ownership Change, the amount of the Company's NOL's 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.
The Company does not expect to report any regular taxable income in the near future because it expects to utilize its carryforwards and other tax deductions and credits. However, there is no assurance that the Internal Revenue Service will not challenge these carryforwards or their utilization.
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.
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 the LA Basin, 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 the LA Basin, 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.
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. A large portion of the Company's reserve base (approximately 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price received by the Company at December 31, 1997, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $18.34 per barrel. During the first quarter of 1998, the NYMEX Crude Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was approximately $16.50 per barrel. 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 Plains Marketing. 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, Liquidity and Financial Condition--Changing Oil and Natural Gas Prices".
Forward Looking-Statements and Associated Risks. This Report includes "forward-looking statements" within the meaning of various provisions of the Securities Act and the Exchange Act. All statements, other than statements of historical facts, included in this Report which address activities, events or developments that the Company expects or anticipates will or may occur in the future, including such things as estimated future net revenues from oil and natural gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of the Company's business and operations, plans, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by the Company in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with the Company's expectations and predictions is subject to a number of risks and uncertainties, including general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by the Company, competitive actions by other oil and natural gas companies, changes in laws or regulations, and other factors, many of which are beyond the control of the Company. Consequently, all of the forward-looking statements made in this Report are qualified by these cautionary statements and there can be no assurance that the actual results or developments anticipated by the Company will be realized or, even if substantially realized, that they will have the expected consequences to or effects on the Company or its business or operations.
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. 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.
EMPLOYEES
As of March 1, 1998, the Company had 230 full-time employees, none of whom is represented by any labor union. Approximately 103 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.
ITEM 2.
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 and the 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 and the Arroyo Grande Field, the Sunniland Trend and the Illinois Basin. The Company's midstream marketing, terminalling and storage activities are concentrated in Oklahoma, Texas, the Gulf Coast area of Louisiana and California. The Company's upstream operations contributed approximately 87% of the Company's EBITDA for the fiscal year ending December 31, 1997, while the Company's midstream activities accounted for the remainder. 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. The Company's midstream operations are conducted through Plains
Marketing. See Item 1, "Business" for a discussion of the Company's acquisition, development, exploitation and exploration activities and midstream businesses.
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. and System Technology Associates Inc. with respect to the California Properties, Netherland, Sewell & Associates, Inc. with respect to the Sunniland Trend and other minor properties, and Ryder Scott Company with respect to the Illinois Basin Properties. 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.
The following table sets forth the Present Value of Proved Reserves as of December 31, 1997, 1996 and 1995.
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 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price received by the Company at December 31, 1997, 1996, and 1995 upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such dates were based, was $18.34 per barrel, $25.92 per barrel and $19.55 per barrel, respectively. Revisions of previous estimates set forth above include downward price related revisions of 16 MMBls in 1997 and positive price related revisions of 10 MMBbls in 1996. During the first quarter of 1998, the NYMEX Crude Oil Price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the NYMEX Crude Oil Price was approximately $16.50 per barrel. 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".
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, 1997, is based on the NYMEX Crude Oil Price received by the Company of $18.34 per barrel with variations therefrom based on location and grade of crude oil. The Company has entered into various fixed and floating price collar arrangements to fix the NYMEX Crude Oil Price for a significant portion of its crude oil production. On December 31, 1997, these arrangements provided for a NYMEX Crude Oil Price for: (i) 12,250 barrels per day from January 1, 1998, through December 31, 1998, at approximately $19.80 per barrel and (ii) 2,000 barrels per day from January 1, 1999, through December 31, 1999, at approximately $20.08 per barrel. Since December 31, 1997, the Company has entered into additional arrangements for 1999, which when combined with arrangements in effect at December 31, 1997, provide for a NYMEX Crude Oil Price for approximately 6,000 barrels per day from January 1, 1999, through December 31, 1999, at $18.55 per barrel. Arrangements in effect at December 31, 1997, are reflected in the reserve reports through the term of the arrangements. 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. The overall average prices used in the reserve reports as of December 31, 1997, were $13.91 per barrel of crude oil, condensate and natural gas liquids and $2.13 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, 1996, 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 16 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, 1997, the Company had working interests in 1,767 gross (1,758 net) active oil wells. These totals do not include the Company's royalty and overriding royalty interests in approximately 141 gross (5 net) producing oil wells.
The following table sets forth certain information with respect to the developed and undeveloped acreage of the Company as of December 31, 1997.
- ------------ (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 1998 through 2001. (4) 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 seismic option. See Item 1, "Exploration--Current Exploration Projects--Sunniland Trend".
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities during the years ended December 31, 1997, 1996 and 1995 is set forth below:
At December 31, 1997, the Company was in the process of drilling 7 gross (7 net) development wells. 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, 1997, 1996 and 1995.
CRUDE OIL STORAGE AND TERMINALLING FACILITIES
In December 1993, the Company completed construction on the first phase of the Cushing Terminal in Cushing, Oklahoma. The first phase of the facility consists of two million barrels of shell storage capacity comprised of fourteen 100,000 barrel capacity tanks and four 150,000 barrel capacity tanks. In addition, the Company owns a 360,000 barrel terminal and dock facility located in Ingleside, Texas, just north of the Port of Corpus Christi. See Item 1, "Business -- Midstream Activities".
OTHER FACILITIES
The Company currently leases offices containing approximately 42,000 square feet in Houston, Texas.
ITEM 3.
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.
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 39, 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., Senior Vice President Officer Since 1984
Mr. Egg, age 46, has been Senior Vice President of the Company since 1991. 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, Controller and Principal Accounting Officer Officer Since 1993
Ms. Feeback, age 40, has been Controller and Principal Accounting Officer of the Company since 1993. She was Controller of the Company from 1990 to 1993 and Accounting Manager from 1988 to 1990.
Phillip D. Kramer, Senior Vice President, Chief Financial Officer and Treasurer Officer Since 1987
Mr. Kramer, age 42, became Senior Vice President and Chief Financial Officer of the Company in May 1997. He was Vice President and Chief Financial Officer from 1992 to 1997, Vice President and Treasurer from 1988 to 1992, Treasurer from 1987 to 1988, and Controller from 1983 to 1987.
Michael R. Patterson, Vice President and General Counsel Officer Since 1985
Mr. Patterson, age 50, has been Vice President and General Counsel of the Company since 1985 and Corporate Secretary since 1988.
Harry N. Pefanis, Senior Vice President Officer Since 1988
Mr. Pefanis, age 40, became Senior Vice President in February 1996. 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 of Plains Marketing & Transportation Inc., a wholly-owned subsidiary of the Company.
Mary O. Peters, Vice President - Administration and Human Resources Officer Since 1991
Ms. Peters, age 49, 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.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's $.10 par value 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 20, 1998, was 1,409.
For the periods indicated below, 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.
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 prohibited by provisions of the indenture governing the issue of $200 million 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and the Company's $165 million revolving credit facility (the "Revolving Credit Facility") from paying dividends on the Common Stock.
ITEM 6.
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".
(1) Includes a $20 million 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, 1993. (2) 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". (3) Relates to the early redemption in March 1996 of the Company's 12% Senior Subordinated Notes due 1999. (4) Net cash provided by operating activities before changes in assets and liabilities. (5) EBITDA means earnings before interest, taxes, depreciation, depletion, amortization and other noncash 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.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
For the three years ended December 31, 1997, the Company reported continued improvement in its fundamental operating and financial results. Upstream production volumes and midstream gross margin, the primary operating drivers for each segment, were up significantly in 1997, versus 1996 and 1995. For the three years ended December 31, 1997, the Company also reported significant increases in proved reserves and cash flow from oil and natural gas producing activities. Such increases are primarily the result of acquisition and exploitation activities in the Company's three core areas of California, the Sunniland Trend and the Illinois Basin. During 1997, the Company added to it's existing LA Basin Properties with the acquisition of the Montebello Field in March, and expanded into another California area with the acquisition of the Arroyo Grande Field in November. Combined, these two fields added approximately 43 million BOE to the Company's proved reserves at the acquisition dates. The Company's three core areas are comprised primarily of crude oil properties and together account for approximately 99% of the Company's year-end 1997 proved reserves. See Item 1, "Business--Acquisition and Exploitation--Current Exploitation Projects".
RESULTS OF OPERATIONS
For the year ended December 31, 1997, the Company reported net income of $14.3 million, or $.85 per share ($.77 per share assuming dilution), on total revenue of $862.2 million compared to net income for 1996 of $16.5 million, or $1.01 per share ($.94 per share assuming dilution). Net income for 1995 was $2.7 million or $.19 per share ($.16 per share assuming dilution). Earnings per share for 1996 and 1995 has been restated in accordance with the provisions of Statement of Financial Accounting Standards No. 128, Earnings per Share. For 1997, the Company reported pretax income of $22.6 million as compared to $17.8 million of pretax income in 1996 on higher oil prices. 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 19% in 1997 to $68.3 million from the $57.2 million reported in 1996 and 105% from the $33.3 million reported in 1995. Cash flow from operations (cash provided by operating activities before changes in assets and liabilities) increased to $46.2 million in 1997, 16% and 135% above the $39.9 million and $19.7 million reported in 1996 and 1995, respectively. Net cash provided by operating activities was $30.3 million for the year ended December 31, 1997, as compared to $39.0 million for 1996 and $17.0 million in 1995. 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:
Oil and natural gas production volumes in 1997 totaled 7.4 million BOE, a 15% increase over the 1996 level of 6.4 million BOE and 52% above the 1995 level of 4.8 million BOE. Approximately 94% of 1997's equivalent production volumes were crude oil. Production volumes increased in each of the Company's three core areas due to the Company's acquisition and exploitation activities. Average net daily production from the Company's California Properties increased to approximately 11,200 BOE per day in 1997, up 2,000 BOE per day, or 22% over 1996 and 33% over the 1995 level. Excluding production from the Montebello and Arroyo Grande Fields which were acquired during 1997, aggregate Company production was up 8% from 1996. Net production from the Company's Sunniland Trend properties averaged approximately 5,300 barrels of oil per day in 1997, a 13% increase compared to 4,700 barrels per day in 1996 and 56% over the 3,400 barrels per day in 1995. 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 3,600 barrels per day during 1997, up 3% over 1996. The Company acquired the Illinois Basin properties in the fourth quarter of 1995.
Oil and natural gas revenues increased to $109.4 million in 1997 as compared to $97.6 million in 1996 and $64.1 million in 1995 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 $14.83 per BOE in 1997, a 3% decrease from the average price received in 1996, and an increase of 12% from the $13.24 per BOE in 1995. The NYMEX Crude Oil Price averaged $20.63 per barrel in 1997, $21.99 per barrel in 1996, and $18.40 per barrel in 1995. 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 decreasing the overall average price per BOE received by the Company by $1.26 in 1997, $2.62 in 1996 and $.17 in 1995. Approximately 78% of the Company's crude oil production was hedged throughout 1997 at an average NYMEX Crude Oil Price of approximately $19.31 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".
Upstream unit gross margin (well-head revenue less production expenses) for 1997 was $8.67 per BOE, compared to $9.18 per BOE in 1996 and $6.99 per BOE in 1995. Average unit production expenses were $6.16 per BOE, $6.04 per BOE and $6.25 per BOE in 1997, 1996, and 1995, respectively. Total production expenses increased to $45.5 million from $38.7 million and $30.3 million in 1996 and 1995, respectively, primarily due to increased production volumes resulting from the Company's acquisition and exploitation activities.
Unit G&A expense in the upstream segment decreased for the fifth consecutive year. Unit G&A expense decreased 12% to $.65 per BOE during 1997 from $.74 per BOE during 1996. Unit G&A expense was $.99 per BOE in 1995, $1.04 per BOE in 1994, $1.34 per BOE in 1993 and $2.48 per BOE in 1992. These reductions were directly attributable to increased production levels and to the Company's ongoing cost control efforts.
As a result of the warm and abnormal weather generally referred to as El Nino, weather patterns throughout the United States have experienced meaningful variances from historical norms. In particular, California has been significantly affected by unusually large amounts of rainfall. Through mid- March 1998, areas within California where the Company's properties are located have experienced actual rainfall exceeding 150% of the rainfall typically received for an entire year. Such rainfall and associated high winds have an adverse effect on the Company's California operations. Specifically, such weather conditions cause erosion, flooding, electrical outages and various other related side effects. Such conditions result in reduced production due to down time and delays in implementing capital projects, as well as increased expenses associated with repair and mitigation costs.
Through mid-March, aggregate production down time caused by El Nino was estimated at approximately 20,000 barrels and incremental operating expenses were estimated at approximately $500,000. While the Company believes it has taken appropriate steps to mitigate the adverse effects of El Nino on its operations, there can be no assurance that the preventative measures will prove effective, and the Company cannot predict the extent to which such adverse weather patterns will continue to impact the Company's 1998 operations, financial results or planned capital program.
Midstream Results
The following table sets forth certain midstream operating information of the Company for the periods presented:
The Company's midstream segment reported gross margin (revenues less direct expenses of purchases, transportation, storage and terminalling) of $12.5 million for the year ended December 31, 1997, reflecting a 31% increase over the $9.5 million reported for the 1996 period and an approximate 96% increase over 1995. Gross profit, which deducts G&A expenses attributable to this segment, totaled $9.0 million for 1997, approximately 37% and 127% over the amounts reported for 1996 and 1995, respectively. Net of interest expense associated with contango inventory transactions, midstream gross margin and gross profit for the current year were $11.6 million and $8.1 million, respectively, representing increases of approximately 22% and 23% over the 1996 respective amounts. Gross revenues from this segment were $752.5 million, $531.7 million and $339.8 million for 1997, 1996 and 1995, respectively. The increases in revenues and profitability are primarily due to increased volumes marketed and activities at the Cushing Terminal. The Company's terminalling and storage activities are generally counter cyclical to its crude oil marketing activities. Typically, marketing margins are strongest in a backward market. During a contango market, when marketing margins are generally smaller, the Company's terminalling and storage operations at the Cushing Terminal typically become more profitable due to (i) the Company's ability to take delivery on crude oil which is simultaneously purchased and resold at a profit for delivery in a subsequent month and (ii) the increased demand by third parties for storage capacity. Storage and terminalling margins were generally stronger in 1997, and marketing margins were stronger in 1996 and 1995. Aggregate marketing and terminalling volumes averaged 140,000 barrels per day in 1997 versus 115,000 barrels per day in 1996 and 88,000 barrels per day in 1995. Midstream G&A expenses were $3.5 million, $3.0
million, and $2.4 million for 1997, 1996 and 1995, respectively. Such increases are primarily attributable to the continued expansion of the Company's marketing and terminalling activities.
General
Total G&A expenses, including midstream activities, were $8.3 million for the year ended December 31, 1997, compared to $7.7 million and $7.2 million for 1996 and 1995, respectively. The increases are primarily attributable to increased expenses associated with the Company's midstream activities. Depreciation, depletion and amortization ("DD&A") per BOE declined to $2.83 in 1997 from $3.00 in 1996 and $3.02 in 1995 primarily as a result of the Company's acquisition and exploitation activities. Primarily as a result of increased production levels, total DD&A for the year ended December 31, 1997 was $23.8 million as compared to $21.9 million and $17.0 million in 1996 and 1995, respectively.
Interest expense, net of capitalized interest, for 1997 increased to $22.0 million as compared to $17.3 million in 1996 and $13.6 million in 1995. The increases are primarily due to (i) higher debt levels related to the Company's acquisition, exploitation, development and exploration activities, including the acquisition of the Montebello Field, (ii) short-term borrowings in 1997 for the purchase of crude oil inventory associated with contango crude oil inventory transactions and (iii) a higher average interest rate, partially attributable to the $50 million add-on to the 10.25% Notes in July 1997. During 1997, 1996 and 1995, the Company capitalized $3.3 million, $3.6 million and $3.1 million of interest, respectively.
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.
For the year ended December 31, 1997, the Company recognized a deferred tax provision of $8.0 million and a current tax provision of $.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 to the $8.5 million pre-tax first quarter extraordinary loss from the early redemption of the Company's 12% Senior Subordinated Notes due 1999 (the "12% Notes"). Although the Company recorded net income for 1995, no provision for income taxes was reflected, but rather the valuation allowance discussed above was adjusted.
The Company has initiated a comprehensive review of its computer systems to identify the systems that could be affected by the "Year 2000" issue. The Company expects to incur internal staff costs as well as some consulting and other expenses necessary to prepare the systems for the year 2000. The Company does not expect the amounts required to be expensed over the next year to have a material effect on its results of operations. The Company expects all Year 2000 issues to be resolved in a timely manner during 1998 and 1999. There can be no assurance that the systems of other companies on which the Company relies also will be converted in a timely manner or that any such failure to convert by another company would not have an adverse effect on the Company. In order to minimize this impact, the Company is in contact with its vendors and customers to work toward their compliance.
In July 1997, the FASB issued Statement of Financial Accounting Standards No. 131 ("SFAS 131"), Disclosures About Segments of an Enterprise and Related Information, effective for fiscal years beginning after December 15, 1997. SFAS 131 introduces a new model for segment reporting and requires disclosures for each segment that are similar to those required under current standards with the addition of quarterly disclosure requirements and a finer partitioning of geographic disclosures. Reportable segments are based on products and services, geography, legal structure, management structure or any manner in which management disaggregates a company. This statement replaces the notion of industry and geographic segments in current FASB standards. Management is currently evaluating the impact of this statement on the Company's disclosures.
CAPITAL RESOURCES, LIQUIDITY AND FINANCIAL CONDITION
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 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 LA Basin 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. As a result of high intert 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 intends to spend approximately $2.5 million during 1998 and 1999 to improve 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 alternative market for the gas production, although such market cannot be assured. See Item 1, "Business--Product Markets and Major Customers". The Montebello Acquisition was funded with proceeds from the Revolving Credit Facility.
On November 12, 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. 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 field was producing approximately 1,600 barrels (approximately 1,500 barrels net to the Company) of 14(degree) API gravity oil per day from 70 wells.
The aggregate purchase price of $22.1 million consisted of (i) rights to a non-producing property interest conveyed to Shell, (ii) the issuance of 46,600 shares of Series D Preferred Stock with an aggregate stated value of $23.3 million and (iii) 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. Each share of the Series D Preferred Stock has a stated value of $500 and is convertible into Common Stock at a ratio of $25.00 of stated value for each share of Common Stock to be issued. Commencing January 1, 2000, the Series D Preferred Stock will bear an annual dividend of $30.00 per share. Prior to such date no dividends will accrue. The Series D Preferred Stock 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. The Series D Preferred Stock was initially recorded at $20.5 million, a discount of $2.8 million from the stated value. This discount will be amortized to retained earnings during the two year period dividends do not accrue.
In March 1997, the Company's Revolving Credit Facility and borrowing base thereunder was increased to $165 million from $125 million. The Revolving Credit Facility, as amended, converts to a term loan on July 1, 1999, with a final maturity of July 1, 2004, and bears interest at the option of the Company at LIBOR plus 1 3/8% or Base Rate (as defined therein). The Revolving Credit Facility is guaranteed by all of the Company's subsidiaries except PMCT Inc. and Plains All American and is secured by the upstream oil and gas properties of the Company and the guaranteeing subsidiaries and the stock of all subsidiaries except Plains All American. At December 31, 1997, the Company had $80 million in borrowings and a $1.0 million standby letter of credit outstanding under the Revolving Credit Facility.
On July 23, 1997, the Company sold $50 million of Senior Subordinated Notes due 2006, Series C, bearing a stated coupon rate of 10.25% (the "Series C 10.25% Notes"). Such notes were issued pursuant to a Rule 144A private placement at approximately 107.21% of par to yield a minimum yield to worst of 8.79%, or 9.03% yield to maturity. On October 30, 1997, the Company exchanged a total of $49.95 million of the Series C 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series D, (the "Series D 10.25% Notes"). The Series D 10.25% Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series C 10.25% Notes for which they were exchanged, except for certain transfer restrictions relating to the Series C 10.25% Notes. 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 outstanding on the Revolving Credit Facility.
The stated coupon rate of interest and maturity date of the Series C 10.25% Notes and the Series D 10.25% Notes (collectively, the "Series C & D 10.25% Notes") are the same as those of the Company's existing $150 million principal amount of senior subordinated notes currently outstanding (the "Series A & B 10.25% Notes"). The Series A 10.25% Notes, the Series B 10.25% Notes, the Series C 10.25% Notes and the Series D 10.25% Notes (collectively, the "10.25% Notes") are redeemable, at the option of the Company, on or after March 15, 2001 at 105.13% 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")).
Plains Marketing has a $90 million Uncommitted Secured Demand Transactional Line of Credit Facility (the "Transactional Facility") with five banks. The purpose of the Transactional Facility is to provide standby letters of credit to support the purchase of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. In August 1997, the sublimit for cash borrowings under the Transactional Facility was increased to $25 million from $20 million. Letters of credit under the Transactional Facility are generally issued for seventy-day periods and bear fees of 1 1/8% per annum. Borrowings incur interest at the option of the borrower at (i) the Base Rate or (ii) LIBOR plus 1 1/2%. At December 31, 1997, approximately $37.8 million in letters of credit and $18.0 million in borrowings were outstanding under the Transactional Facility.
The Transactional Facility is secured by all of the assets of Plains Marketing and is guaranteed by the Company. The Company's guarantee is secured by a $1.0 million standby letter of credit issued on behalf of the Company. All financings under the Transactional Facility, which expires in November 1998, are at the discretion of the lenders.
At December 31, 1997, the Company had a working capital deficit of approximately $6.0 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, 1996 and 1995, were $4.8 million and $4.7 million, respectively.
On March 21, 1998, Plains All American entered into a definitive agreement to acquire all of the outstanding capital stock of the Celeron Companies from Goodyear. Aggregate proceeds to Goodyear through closing are estimated at $420 million. The principal assets of the entities to be 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. The purchase price is subject to certain adjustments through the closing date, and the transaction is subject to regulatory review and approval by the United States Department of Justice and the Federal Trade Commission under the Hart- Scott-Rodino Anti-Trust Improvements Act of 1976, as amended, and by the Public Utilities Commission of the State of California. The transaction is expected to be completed in the third quarter of 1998 after regulatory approvals have been secured.
A major source of financing for the transaction will be provided through a new $325 million, limited recourse bank facility made available to Plains All American by ING Barings and BankBoston, N.A. In addition to the bank facility, the Company will make a capital contribution to Plains All American of up to $130 million which will be used to fund the balance of the purchase price and transaction costs and provide initial working capital. To finance its capital contribution, the Company will borrow approximately $50 million under the Revolving Credit Facility and has entered into financing commitments for a new issue of privately placed, convertible preferred stock aggregating approximately $80 million. Commitments for the preferred stock placement have been obtained from a group of equity investors comprised primarily of existing shareholders. The preferred stock has an aggregate stated value of $80 million and bears a cumulative dividend of 9.5% per annum, payable semi-annually in either cash or additional shares of preferred stock at the Company's option. Each share of preferred stock is convertible into 27.78 shares of Common Stock (an 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 preferred stock is redeemable at the option of the Company at 110% of stated value after March 31, 1999, and at
declining amounts thereafter. If not previously redeemed or converted, the preferred stock is required to be redeemed in 2012.
The All American Pipeline is the single largest crude oil pipeline connecting California to West Texas, where it connects with pipelines that transport crude oil to Cushing, Oklahoma and the Gulf Coast. The Cushing Interchange is the largest crude oil trading location in the United States and the designated delivery point for the NYMEX crude oil futures contract. At Cushing, the Company owns and operates the Cushing Terminal, the largest terminal facility in Cushing not owned by a major oil company and the fourth largest overall. The 45-mile gathering system is located in the San Joaquin Valley, currently the most prolific crude oil producing region in the continental United States. The areas serviced by the pipeline and gathering system currently produce over 700,000 barrels of crude oil per day, representing approximately 15% of total oil production in the continental United States. For 1997, the operations to be acquired generated approximately $65 million in EBITDA.
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 $103 million in 1998, including approximately $91 million on the development and exploitation of its California, Sunniland Trend and Illinois Basin properties, approximately $6 million on exploration activities primarily in the Sunniland Trend and approximately $6 million for various other capital items. 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.
Changing Oil and Natural Gas Prices
The Company is 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 have a negative impact on the Company's overall results, and therefore its liquidity. Furthermore, low crude oil prices could affect the Company's ability to raise capital on terms favorable to the Company. In order to manage its exposure to commodity price risk, the Company has routinely hedged a portion of its crude oil production. For 1998, the Company has entered into various fixed price and floating price collar arrangements. Such arrangements generally provide the Company with downside price protection on approximately 12,250 barrels of oil per day at a NYMEX Crude Oil Price of approximately $19.80 per barrel. Thus, based on the Company's average fourth quarter 1997 crude oil production rate, these arrangements generally provide the Company with downside price protection for approximately 60% of its production. In addition, the Company also has fixed price arrangements on 6,000 barrels per day in 1999 at a NYMEX Crude Oil Price of $18.55 per barrel, or approximately 30% of fourth quarter 1997 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".
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. A large portion of the Company's reserve base (approximately 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price received by the Company at December 31, 1997, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $18.34 per barrel. During the first quarter of 1998, the benchmark NYMEX crude oil price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the benchmark NYMEX crude oil price was approximately $16.50 per barrel. 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 Present Value of Proved Reserves reduced by future discounted income taxes (the "Standardized Measure"). At December 31, 1997, the Standardized Measure of the Company's proved reserves was greater than the book carrying cost of the Company's oil and gas properties by approximately $85 million. Subject to ongoing exploitation and production activities which may affect the estimated volumes and values of the Company's
oil and gas properties, the Company estimates that the Standardized Measure of the Company's proved reserves will approximate the book carrying cost of such properties at a NYMEX benchmark crude oil price between $15.00 and $16.00 per barrel and the Company could be required to record a noncash writedown of such capitalized costs.
Investing Activities
Net cash flows used in investing activities were $107.6 million, $52.5 million and $64.4 million for the years ended December 31, 1997, 1996 and 1995, respectively. Included in such amounts are payments, net of cash received from property sales and reimbursements from partners, for acquisition, development and exploration costs of $103.0 million, $49.9 million and $63.9 million for the same periods, respectively. Such payments for 1997 and 1995 include $22.0 million and $45.0 million related to the acquisition of the Montebello Field and the Illinois Basin Properties, respectively. The Company expended $4.7 million, $2.6 million and $1.1 million in 1997, 1996 and 1995, 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 $78.5 million, $9.9 million and $52.3 million for 1997, 1996 and 1995, respectively. Aggregate proceeds from long-term borrowings for these same years were $266.9 million, $263.7 million and $83.6 million, respectively, while payments of long-term debt were $207.0 million, $248.1 million and $32.7 million for the respective periods. 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 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 Series A & B 10.25% Notes, approximately $107 million for the repayment of the 12% Notes, including the 6% call premium and the net defeasance costs, and approximately $42 million for the repayment of the Illinois Basin acquisition bridge indebtedness. The Illinois Basin acquisition indebtedness of $42 million is included in aggregate financing proceeds for 1995. Remaining long-term debt activity is primarily related to advances received and payments made on the Revolving Credit Facility. Financing activities during 1997 include proceeds of $39 million from short-term borrowings and $21 million of repayments related to crude oil inventory transactions at the Cushing Terminal. The short-term borrowings were made under the Transactional Facility and all inventory acquired has been hedged against price risk. Financing activities include proceeds from the sale of capital stock of $1.1 million, $1.8 million and $.9 million in 1997, 1996 and 1995, 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 $11.0 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 1997, 1996 and 1995 include $.6 million, $.8 million and $1.0 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.
ITEM 8.
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 to and such information is incorporated herein by reference.
ITEM 9.
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.
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 1998 Annual Meeting of Stockholders (the "Proxy Statement") to be filed within 120 days after December 31, 1997, 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.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information regarding executive compensation will be included in the Proxy Statement and is incorporated herein by reference.
ITEM 12.
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.
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.
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 hereof.
(2) Exhibits
- --------------- *A management contract or compensation plan.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the fourth quarter of 1997.
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 26, 1998 By: /s/ Phillip D. Kramer -------------------------------------------- Phillip D. Kramer, Senior 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 26, 1998 By: /s/ Greg L. Armstrong -------------------------------------------- Greg L. Armstrong, President, Chief Executive Officer and Director (Principal Executive Officer)
Date: March 26, 1998 By: /s/ Jerry L. Dees -------------------------------------------- Jerry L. Dees, Director
Date: March 26, 1998 By: /s/ Tom H. Delimitros -------------------------------------------- Tom H. Delimitros, Director
Date: March 26, 1998 By: /s/ Cynthia A. Feeback -------------------------------------------- Cynthia A. Feeback, Controller and Principal Accounting Officer (Principal Accounting Officer)
Date: March 26, 1998 By: /s/ William M. Hitchcock -------------------------------------------- William M. Hitchcock, Director
Date: March 26, 1998 By: /s/ Phillip D. Kramer -------------------------------------------- Phillip D. Kramer, Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Date: March 26, 1998 By: /s/ Dan M. Krausse -------------------------------------------- Dan M. Krausse, Chairman of the Board and Director
Date: March 26, 1998 By: /s/ John H. Lollar -------------------------------------------- John H. Lollar, Director
Date: March 26, 1998 By: /s/ Robert V. Sinnott -------------------------------------------- Robert V. Sinnott, Director
Date: March 26, 1998 By: /s/ J. Taft Symonds -------------------------------------------- J. Taft Symonds, Director
The Annual Report to Stockholders of the Company for the year ended December 31, 1997, 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.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, 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.
PRICE WATERHOUSE LLP
/s/Price Waterhouse
Houston, Texas February 19, 1998
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (IN THOUSANDS)
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"), and its wholly-owned subsidiaries. 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 and the marketing, transportation, terminalling and storage of crude oil. The Company's upstream oil and natural gas activities are focused in California, the Sunniland Trend of South Florida (the "Sunniland Trend") and the Illinois Basin in southern Illinois. Its midstream marketing activities are concentrated in Oklahoma, where it owns a two million barrel, above ground crude oil terminalling and storage facility (the "Cushing Terminal"), Texas, the Gulf Coast area of Louisiana and California.
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.
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 16).
OTHER PROPERTY AND EQUIPMENT
Other property and equipment is recorded at cost. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation on the Cushing Terminal is provided using the straight-line method over an estimated useful life of forty years; other property and equipment is also depreciated using the straight-line method over estimated useful lives of three to seven years.
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. Debt issue costs, net of accumulated amortization, as of December 31, 1997 and 1996, in the amount of $4.7 million and $5.0 million, respectively, are included in "Other Assets" in the accompanying Consolidated Balance Sheets.
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 AND STORAGE
The Company's midstream activities are conducted through various wholly- owned subsidiaries collectively referred to as ("Plains Marketing"). Plains Marketing markets principally crude oil of third party producers as well as crude oil and natural gas produced by the Company. Marketing and transportation revenue is accrued at the time title to the product sold transfers to the purchaser and purchases are accrued at the time title to the product purchased transfers to Plains Marketing. Except for crude oil purchased from time to time as inventory to service the needs of its terminalling and storage customers, the Company's policy is 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.
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 New York Mercantile Exchange ("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.
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 and storage 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 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.
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 10).
NOTE 2 -- INVENTORY
Inventory consists of the following:
DECEMBER 31, ------------------------------ 1997 1996 ------- ------- (IN THOUSANDS) Crude oil............................... $18,986 $2,536 Materials and supplies.................. 3,816 2,027 ------- ------ $22,802 $4,563 ======= ======
At December 31, 1997, approximately 77% of the crude oil inventory was 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.
NOTE 3 -- LONG-TERM DEBT
Long-term debt consists of the following:
REVOLVING CREDIT FACILITY
The Company has a $165 million revolving credit facility (the "Revolving Credit Facility") with a group of six banks (the "Lenders"). The Revolving Credit Facility is guaranteed by all of the Company's subsidiaries except PMTI Inc. and Plains All American Inc. ("Plains All American") and is secured by the upstream oil and gas properties of the Company and the guaranteeing subsidiaries except Plains All American and the stock of all subsidiaries except Plains All American. The Cushing Terminal is not pledged as security for any of the Company's debt. The borrowing base under the Revolving Credit Facility at December 31, 1997, is set at $165 million and 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 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, 1999, at which time the remaining outstanding balance converts to a term loan which is repayable in twenty equal quarterly installments commencing October 1, 1999, with a final maturity of July 1, 2004. 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, 1997, outstanding borrowings under the Revolving Credit Facility were $80 million. In addition to the amount outstanding at December 31, 1997, $1 million was reserved against the issuance of a standby letter of credit.
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 provide that the Company must maintain a specified relationship between current assets and current liabilities.
10.25% SENIOR SUBORDINATED NOTES DUE 2006
On July 23, 1997, the Company sold $50 million of Senior Subordinated Notes due 2006, Series C, bearing a stated coupon rate of 10.25% (the "Series C 10.25% Notes"). Such notes were issued pursuant to a Rule 144A private placement at approximately 107.21% of par to yield a minimum yield to worst of 8.79%, or 9.03% yield to maturity. On October 30, 1997, the Company exchanged a total of $49.95 million of the Series C 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series D, (the "Series D 10.25% Notes"). The Series D 10.25% Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series C 10.25% Notes for which they were exchanged, except for certain transfer restrictions relating to the Series C 10.25% notes. The stated coupon rate of interest and maturity date of the Series C 10.25% Notes and the Series D 10.25% Notes (collectively, the "Series C & D 10.25% Notes") are the same as those of the Company's Series A & B 10.25% Notes. 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 outstanding on the Revolving Credit Facility.
On March 19, 1996, the Company sold $150 million of Senior Subordinated Notes due 2006, Series A, bearing a coupon rate of 10.25% (the "Series A 10.25% Notes"). Such notes were issued pursuant to a Rule 144A private placement at approximately 99.38% of the principal amount thereof to yield 10.35%. On August 8, 1996, the Company exchanged a total of $149.5 million principal amount of the Series A 10.25% Notes for 10.25% Senior Subordinated Notes due 2006, Series B, (the "Series B 10.25% Notes"). The Series B 10.25% Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series A 10.25% Notes for which they were exchanged, except for certain transfer restrictions relating to the Series A 10.25% Notes.
Proceeds from the sale of the Series A & 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 all of the upstream oil and gas assets of Marathon Oil Company ("Marathon") in the Illinois Basin (the "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 tax, in connection therewith.
The Series A 10.25% Notes, the Series B 10.25% Notes, the Series C 10.25% Notes and The Series D 10.25% Notes (collectively, the "10.25% Notes") are redeemable, at the option of the Company, on or after March 15, 2001 at 105.13% 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.
OTHER LONG-TERM DEBT
Included in other long-term debt at December 31, 1997 and 1996 is $3.6 million and $4.1 million, respectively, related to the 1995 acquisition of a production payment burdening certain of the Company's California properties. Such other long-term debt has maturities of approximately $.5 million per year in each of the years 1998 through 2004.
The aggregate amount of maturities of all long-term indebtedness for the next five years is: 1998 - $.5 million, 1999 - $4.5 million, 2000 - $16.5 million, 2001 - $16.5 million and 2002 - $16.5 million.
NOTE 4 -- UNCOMMITTED SECURED DEMAND TRANSACTIONAL LINE OF CREDIT FACILITY
Plains Marketing has a $90 million Uncommitted Secured Demand Transactional Line of Credit Facility (the "Transactional Facility") with five banks. The purpose of the Transactional Facility is to provide standby letters of credit to support the purchase of crude oil for resale and borrowings to finance crude oil inventory which has been hedged against future price risk. The Transactional Facility is secured by all of the assets of Plains Marketing, primarily accounts receivable and crude oil inventory, and is guaranteed by the Company. The Company's guarantee is secured by a $1 million standby letter of credit issued on behalf of the Company under the Revolving Credit Facility.
Plains Marketing has established a $25 million sublimit (the "Sublimit") within the Transactional Facility for borrowings to finance crude oil purchased in connection with operations at the Cushing Terminal. Under the terms of the Sublimit, 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, 1997, approximately $37.8 million in letters of credit and $18.0 million in borrowings were outstanding under the Transactional Facility.
Letters of credit under the Transactional Facility are generally issued for up to seventy day periods and bear fees of 1 1/8% per annum. Borrowings incur interest at the borrower's option of either (i) the Base Rate, as defined, or (ii) LIBOR plus 1 1/2%. All financings under the Transactional Facility, which expires in November 1998, are at the discretion of the lenders. Aggregate cash borrowings are limited to $25 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, 1997, there were 16.7 million shares of common stock ("Common Stock") issued and outstanding and 46,600 shares of preferred stock outstanding. (See Note 18)
STOCK WARRANTS AND OPTIONS
At December 31, 1997, 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 10).
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.
$1.30 PREFERRED STOCK
On October 31, 1995, all outstanding shares of the Company's $1.30 Cumulative Convertible Preferred Stock (the "$1.30 Preferred Stock") were redeemed for $10 per share plus unpaid and accrued dividends of $.0325 per share. The Company paid a total of $496,000, including unpaid dividends, to redeem the $1.30 Preferred Stock.
REDEEMABLE PREFERRED STOCK
On January 2, 1995, the Company paid a dividend on its Series C Cumulative Convertible Preferred Stock (the "Series C Preferred Stock") for the period of July 14, 1994, through December 31, 1994. The dividend amount of approximately $937,000 was paid by issuing additional shares of the Series C Preferred Stock. On May 25, 1995, all 209,370 outstanding shares of the Series C Preferred Stock, including accrued dividends, were converted into approximately 3.6 million shares of Common Stock.
NOTE 6 -- EARNINGS PER SHARE
In February 1997, the FASB issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"), Earnings Per Share ("EPS"). SFAS 128 replaces the presentation of primary EPS with a presentation of basic EPS and requires a dual presentation of basic and diluted EPS on the face of the income statement for all entities with complex capital structures. 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. SFAS 128 is effective for periods ending after December 15, 1997, and requires restatement of all prior period EPS data presented.
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 1997, 1996 and 1995, as required by SFAS 128. All prior period EPS data has been restated in accordance with the provisions of SFAS 128.
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 Company's Series D Preferred Stock, which was issued during 1997, is convertible into 932,000 shares of Common Stock but was not included in the computation of diluted EPS because the effect was antidilutive. See Notes 5 and 10 for additional information concerning outstanding options and warrants.
NOTE 7 -- INCOME TAXES
The Company's deferred income tax assets (liabilities) at December 31, 1997 and 1996 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain acquisition, exploration, exploitation and development costs for financial and tax reporting as follows:
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 NOL's generated prior to certain of the Company's subsidiaries being acquired and the uncertainty of utilizing the Company's investment tax credit ("ITC") carryforwards. While the Company's tax planning strategies address certain of these restrictions on the application of subsidiary NOL's, management is currently uncertain as to the extent such strategies will be successful and therefore concluded that a reserve for these amounts was appropriate.
At December 31, 1997, the Company had carryforwards of approximately $171.6 million of regular tax NOL's, $7 million of statutory depletion, $.5 million of ITC and $.5 million of alternative minimum tax ("AMT") credit. Of these amounts, utilization of approximately $12.2 million of the NOL carryforwards and $.4 million of the ITC carryforwards are limited to certain companies within the consolidated group. At December 31, 1997, the Company had approximately $159.2 million of AMT NOL carryforwards available as a deduction against future AMT income. The NOL carryforwards expire from 1998 through 2011.
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 Income:
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, 1997.
NOTE 8 -- ACQUISITIONS AND DISPOSITIONS
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.
On November 12, 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 degree 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.
On December 22, 1995, Plains Illinois Inc., a wholly owned subsidiary of the Company, acquired the Illinois Basin Properties, effective November 1, 1995. The aggregate purchase price was approximately $51.5 million including associated transaction costs, of which approximately $6.5 million was paid for by the issuance of 798,143 shares of Common Stock and the remaining $45 million was paid in cash. The cash portion of the purchase price was financed through a combination of advances under the Revolving Credit Facility and $42 million of bridge bank indebtedness. The Illinois Basin Properties include three Marathon operated oil fields, various nonoperated producing properties and all of Marathon's oil and natural gas mineral interests, surface fee and undeveloped leasehold within the Illinois Basin as well as Marathon's geological, geophysical and engineering database for the entire region. At the acquisition date, the Illinois Basin Properties added approximately 17.3 million barrels to the Company's proved oil reserves.
In December 1995, Stocker Resources Inc. ("Stocker"), a wholly-owned subsidiary of the Company, acquired from Chevron a production payment burdening certain of Stocker's California properties. The production payment had a face amount of approximately $30 million and was accounted for in prior periods as an overriding royalty interest. Stocker also acquired a fifteen year term mineral interest in certain of its California properties and approximately ten acres of surface fee land in Los Angeles County. These assets were acquired in connection with a settlement agreement resolving certain outstanding issues between Chevron and Stocker. In return for the conveyance of the foregoing assets, Stocker agreed to forgive certain amounts due it, dismiss existing lawsuits related to such claims and issue to Chevron a ten year note for $4.6 million. The settlement also provides for a modification of Stocker's existing contractual obligations to Chevron to plug inactive wells, that Stocker continue its present activities to remediate oil contaminated soil from existing wellsites on an accelerated basis, and for the Company to guarantee the performance of such obligations.
During 1997, 1996 and 1995, the Company sold certain non-strategic oil and natural gas properties located primarily in the Gulf Coast areas of Texas and Louisiana and in Utah for net proceeds of approximately $2.7 million, $3.1 million and $7.4 million, respectively.
NOTE 9 -- 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, 1997 and 1996, is comprised of the following components:
The following schedule reconciles the status of the Plan with amounts reported in the Company's balance sheet at December 31, 1997 and 1996.
The weighted-average discount rate used in determining the projected benefit obligation was 7% and 8% for the years ended December 31, 1997 and 1996, respectively.
NOTE 10 -- 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, 1997, 1996, and 1995, and changes during the years ending on those dates are presented below:
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 1997, 1996 and 1995: risk-free interest rates of 6.1% for 1997, 6.0% for 1996 and 7.5% for 1995; a volatility factor of the expected market price of the Company's common stock of .42 for 1997 and .36 for 1996 and 1995; no expected dividends; and weighted-average expected option lives of 2.6 years in 1997, 2.7 years in 1996 and 3.5 years in 1995.
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.
The following table summarizes information about stock options outstanding at December 31, 1997:
During 1997 and 1996, pursuant to Board of Directors' resolutions, the Company contributed approximately 21,000 and 18,000 shares, respectively, of Common Stock at weighted average prices of $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.
NOTE 11 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
COMMITMENTS AND CONTINGENCIES
Minimum commitments in connection with office space and office equipment leased by the Company are: 1998 - $.8 million; 1999 through 2002 - $.7 million annually; thereafter - $2.4 million. Rental payments made under the terms of similar arrangements totaled approximately $1.1 million in 1997 and in 1996 and $1.2 million in 1995.
In connection with its crude oil marketing, Plains Marketing provides certain purchasers and transporters with irrevocable standby letters of credit to secure the Company'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, 1997, Plains Marketing had outstanding letters of credit of approximately $37.8 million. Such letters of credit are secured by the crude oil inventory and accounts receivable of Plains Marketing and are guaranteed by the Company. To date, no amounts have been drawn on such letters of credit issued by the Company.
Under the amended terms of the asset purchase agreement between Stocker and Chevron, commencing with the year beginning January 1, 2000, and each year thereafter, Stocker 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, Stocker 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 Stocker
does not expend the required amounts during a calendar year, Stocker is required to contribute an amount equal to 125% of the actual shortfall to an escrow account. Stocker may withdraw amounts from such escrow account to the extent it expends excess amounts in a future year. As of December 31, 1997, Stocker 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, Stocker 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 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, 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 $11 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 1997, 1996 and 1995 include $.6 million, $.8 million and $1 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 16.
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, 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.
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 12 -- 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.
NOTE 13 -- MAJOR CUSTOMERS
Sales to Koch Oil Company ("Koch") and Sempra Energy Trading Corporation (formerly AIG Trading Corporation) accounted for 27% and 11%, respectively, of the Company's total revenue (exclusive of interest and other income) during 1997. Customers accounting for more than 10% of total revenue for 1996 and 1995 were as follows: 1996 -- Koch - 16% and Basis Petroleum, Inc. ("Basis", formerly Phibro Energy USA, Inc.) - 11%; 1995 -- Phibro Inc. ("Phibro") - 16% and Basis - 12%. No other single customer accounted for as much as 10% of total sales during 1997, 1996 or 1995. Additionally during 1997, Unocal Energy Trading, Inc., Marathon Oil Company and Exxon Company U.S.A. accounted for approximately 52%, 23% and 10%, respectively, of the Company's oil and gas sales.
NOTE 14 -- 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 fixed and floating price collar 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, 1997, these arrangements provided for a NYMEX Crude Oil Price for: (i) approximately 12,250 barrels per day from
January 1, 1998, through December 31, 1998, at approximately $19.80 per barrel and (ii) 2,000 barrels per day from January 1, 1999, through December 31, 1999, at approximately $20.08 per barrel. Since December 31, 1997, the Company has entered into additional arrangements for 1999, which when combined with arrangements in effect at December 31, 1997, provide for a NYMEX Crude Oil Price for approximately 6,000 barrels per day from January 1, 1999, through December 31, 1999, at $18.55 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.
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. The carrying amounts and fair values of the Company's other financial instruments are as follows:
- --------------- (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, 1997 and 1996. Such hedges, and therefore the unrealized gains and losses, have been included in estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 16.
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.
NOTE 15 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows:
NOTE 16 -- 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.
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.
The DD&A rate per equivalent unit of production was $2.83, $3.00 and $3.02 for the years ended December 31, 1997, 1996 and 1995, 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.
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 37%, 6% and 30% of the balance in unproved properties at December 31, 1997, related to additions made in 1997, 1996 and 1995, respectively.
During 1997, 1996 and 1995, the Company capitalized $3.3 million, $3.6 million and $3.1 million, respectively, of interest related to the costs of unproved properties in the process of development.
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, 1997. The following reserve information is based upon reports of the independent petroleum consulting firms of H.J. Gruy and Company and System Technology Associates Inc. with respect to the Company's California properties, Netherland Sewell & Associates, Inc. with respect to the Sunniland Trend properties and other minor properties and Ryder Scott Company with respect to the Illinois Basin Properties. 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.
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, 1997.
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:
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, 1997, is based on the NYMEX Crude Oil Price of $18.34 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, 1997, are reflected in the reserve reports through the term of the arrangements (See Note 14). The overall average prices used in the reserve reports as of December 31, 1997, were $13.91 per barrel of crude oil, condensate and natural gas liquids and $2.13 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 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") to be $511.0 million, $764.8 million and $366.8 million at December 31, 1997, 1996 and 1995, 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.
The principal sources of changes in the Standardized Measure of future net cash flows for the three years ended December 31, 1997, are as follows:
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. A large portion of the Company's reserve base (approximately 94% of year-end 1997 reserve volumes) is comprised of long-life oil properties that are sensitive to crude oil price volatility. The crude oil price received by the Company at December 31, 1997, upon which proved reserve volumes, the Present Value of Proved Reserves and the Standardized Measure as of such date were based, was $18.34 per barrel. During the first quarter of 1998, the benchmark NYMEX crude oil price fluctuated significantly, closing as high as $17.82 per barrel and as low as $13.21 per barrel. At March 23, 1998, the benchmark NYMEX crude oil price was approximately $16.50 per barrel. At December 31, 1997, the Standardized Measure (See Note 1) of the Company's proved reserves was greater than the book carrying cost of the Company's oil and gas properties by approximately $85 million. Subject to ongoing exploitation and production activities which may affect the estimated volumes and values of the Company's oil and gas properties, the Company estimates that the Standardized Measure of the Company's proved reserves will approximate the book carrying cost of such properties at a NYMEX benchmark crude oil price between $15.00 and $16.00 per barrel and the Company could be required to record a noncash writedown of such capitalized costs.
NOTE 17 -- QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table shows summary financial data for 1997 and 1996.
NOTE 18 -- SUBSEQUENT EVENT -- ALL AMERICAN PIPELINE ACQUISITION (UNAUDITED)
On March 21, 1998, Plains All American, a wholly owned subsidiary of the Company, entered into a definitive agreement to acquire 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 The Goodyear Tire & Rubber Company ("Goodyear"). Aggregate proceeds to Goodyear through closing are estimated at $420 million. The principal assets of the entities to be 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. The purchase price is subject to certain adjustments through the closing date, and the transaction is subject to regulatory review and approval. The transaction is expected to be completed in the third quarter of 1998 after regulatory approvals by the United States Department of Justice and the Federal Trade Commission under the Hart-Scott-Rodino Anti-Trust Improvements Act of 1976, as amended, and by the Public Utilities Commission of the State of California have been secured. For 1997, the operations to be acquired generated approximately $65 million in earnings before interest, taxes, depreciation and amortization.
A major portion of the financing for the transaction will be provided through a new $325 million, limited recourse bank facility made available to Plains All American by ING Barings and BankBoston N.A. In addition to the bank facility, the Company will make a capital contribution to Plains All American of up to $130 million which will be used to fund the balance of the purchase price and transaction costs and provide initial working capital. To finance its capital contribution, the Company will borrow approximately $50 million under the Revolving Credit Facility and has entered into financing commitments for a new issue of privately placed, convertible preferred stock aggregating approximately $80 million. Commitments for the preferred stock placement have been obtained from a group of equity investors comprised primarily of existing shareholders. The preferred stock has an aggregate stated value of $80 million and bears a cumulative dividend of 9.5% per annum, payable semi-annually in either cash or additional shares of preferred stock at the Company's option. Each share of preferred stock is convertible into 27.78 shares of Common Stock (an 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 preferred stock is redeemable at the option of the Company at 110% of stated value after March 31, 1999 and at declining amounts thereafter. If not previously redeemed or converted, the preferred stock is required to be redeemed in 2012.