ITEM 2. PROPERTIES
We are an independent energy company that is engaged in two related lines of business. Our first line of business, which we refer to as "upstream", acquires, exploits, develops, explores and produces crude oil and natural gas. Our second line of business, which we refer to as "midstream", is engaged in the marketing, transportation and terminalling of crude oil. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in PAA. Our upstream crude oil and natural gas activities are focused in California in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field, California OCS in the Point Arguello Field, the Sunniland Trend of South Florida and the Illinois Basin in southern Illinois. Our midstream activities are concentrated in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of Mexico.
OIL AND NATURAL GAS RESERVES
The following tables set forth certain information with respect to our reserves based upon reserve reports prepared by the independent petroleum consulting firms of H.J. Gruy and Associates, Inc., Netherland, Sewell & Associates, Inc., and Ryder Scott Company. 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 pre-tax Present Value of Proved Reserves at December 31, 2000, 1999 and 1998.
There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Present Value of Proved Reserves shown above represents estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. The information set forth in the preceding tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices. A large portion of our reserve base (approximately 94% of year-end 2000 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook".
In accordance with the SEC guidelines, the reserve engineers' estimates of future net revenues from our properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The crude oil price in effect at December 31, 2000 is based on the year-end crude oil price with variations therefrom based on location and quality of crude oil. The overall average prices used in the reserve reports as of December 31, 2000 were $21.02 per barrel of crude oil, condensate and natural gas liquids and $14.63 per Mcf of natural gas. See Item 1. - "Business -- Product Markets and Major Customers". Historically, the prices for
crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. See Item 7. - "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Outlook".
Since December 31, 1999, we have not filed any estimates of total proved net crude oil or natural gas reserves with any federal authority or agency other than the SEC. See Note 20 in our consolidated financial statements appearing elsewhere in this report for certain additional information concerning our proved reserves.
PRODUCTIVE WELLS AND ACREAGE
As of December 31, 2000, we had working interests in 1,875 gross (1,855 net) active producing oil wells. The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2000.
- ------------ (1) Developed acres are acres spaced or assigned to productive wells. (2) Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves. (3) Less than 10% of total net undeveloped acres are covered by leases that expire from 2001 through 2003. (4) Does not include 9,000 acres covered by a farmout from Chevron, in which we own a 46.25% interest. (5) Does not include 6,200 acres under an option agreement, in which we have the right to acquire a 26.315% interest.
DRILLING ACTIVITIES
Certain information with regard to our drilling activities during the years ended December 31, 2000, 1999 and 1998 is set forth below:
See Item 1. - "Business -- Acquisition and Exploitation" and -- "Productive Wells and Acreage" for additional information regarding exploitation activities, including waterflood patterns, workovers and recompletions.
PRODUCTION AND SALES
The following table presents certain information with respect to crude oil and natural gas production attributable to our properties, the revenue derived from the sale of such production, average sales prices received and average production costs during the three years ended December 31, 2000, 1999 and 1998.
PAA PROPERTIES
See description of PAA's properties under Item 1. - "Business - Midstream Activities".
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of our common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933.
We and PAA reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, PAA deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and PAA, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to us by agreement between special independent committees of our board of directors and the board of directors of Plains All American Inc. All such amounts were reflected in our financial statements at December 31, 2000. The settlement is subject to a number of conditions, including final approval by the court. A hearing is set for March 30, 2001. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to PAA and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under
the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Sussex v. Plains All American Inc. as the operative complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000.
The plaintiffs in the Delaware derivative litigation seek that the defendants
. account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses;
. establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices to Plains All American;
. pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees; and
. provide the plaintiffs any additional relief as may be just and proper under the circumstances.
We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court for the Southern District of Texas entitled Fernandez v. Plains All American Inc., et al., naming the general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000.
We intend to vigorously defend the claims made in Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial position or results of operation.
We, in the ordinary course of business, are a claimant and/or a defendant in various other legal proceedings. Management does not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
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 our executive officers is presented below. All executive officers hold office until their successors are elected and qualified.
Greg L. Armstrong, President and Chief Executive Officer Officer Since 1981
Mr. Armstrong, age 42, has been President, Chief Executive Officer and a director since 1992. He was President and Chief Operating Officer from October to December 1992, and Executive Vice President and Chief Financial Officer from June to October 1992. He was Senior Vice President and Chief Financial Officer from 1991 to June 1992, Vice President and Chief Financial Officer from 1984 to 1991, Corporate Secretary from 1981 to 1988, and Treasurer from 1984 to 1987.
William C. Egg, Jr., Executive Vice President Officer Since 1984
Mr. Egg, age 49, has been Executive Vice President and Chief Operating Officer-Upstream since May 1998. He was Senior Vice President from 1991 to 1998. He was Vice President-Corporate Development from 1984 to 1991 and Special Assistant-Corporate Planning from 1982 to 1984.
Cynthia A. Feeback, Vice President - Accounting and Assistant Treasurer Officer Since 1993
Ms. Feeback, age 43, has been Vice President - Accounting and Assistant Treasurer since May 1999. She was Assistant Treasurer, Controller and Principal Accounting Officer of the Company from May 1998 to May 1999. She was Controller and Principal Accounting Officer from 1993 to 1998. She was Controller from 1990 to 1993 and Accounting Manager from 1988 to 1990.
Jim G. Hester, Vice President - Business Development and Acquisitions Officer Since 1999
Mr. Hester, age 41, has been Vice President - Business Development and Acquisitions since May 1999. He was Manager of Business Development and Acquisitions from 1997 to May 1999, Manager of Corporate Development from 1995 to 1997 and Manager of Special Projects from 1993 to 1995. He was Assistant Controller from 1991 to 1993, Accounting Manager from 1990 to 1991 and Revenue Accounting Supervisor from 1988 to 1990.
Phillip D. Kramer, Executive Vice President, Chief Financial Officer and Treasurer Officer Since 1987
Mr. Kramer, age 45, has been Executive Vice President and Chief Financial Officer since May 1998. He was Senior Vice President and Chief Financial Officer from May 1997 to May 1998. He was Vice President and Chief Financial Officer from 1992 to 1997, Vice President from 1988 to 1992, Treasurer from 1987 to March 2001, and Controller from 1983 to 1987.
Tim Moore, Vice President and General Counsel Officer Since 2000
Mr. Moore, age 43, has been Vice President, General Counsel and Secretary since May 2000. Prior to joining Plains Resources, he served as General Counsel - - Corporate of TransTexas Gas Corporation. He previously was a corporate attorney with the Houston office of Weil, Gotshal & Manges. Mr. Moore also has seven years of industry experience as a petroleum geologist.
Harry N. Pefanis, Executive Vice President Officer Since 1988
Mr. Pefanis, age 43, has been Executive Vice President-Midstream since May 1998. He was Senior Vice President from February 1996 to May 1998. He had been Vice President-Products Marketing since 1988. From 1987 to 1988 he was Manager of Products Marketing. From 1983 to 1987 he was Special Assistant for Corporate Planning. Mr. Pefanis is also President and Chief Operating Officer of Plains All American Inc.
Mary O. Peters, Vice President - Administration and Human Resources Officer Since 1991
Ms. Peters, age 52, has been Vice President-Administration and Human Resources since 1991. She was Manager of Office Administration from 1984 to 1991.
Al Swanson, Treasurer Officer Since 2001
Mr. Swanson, age 37, has been Treasurer since February 2001. He was Director of Treasury of the Company from November 2000 to February 2001. Prior to joining Plains Resources, he served as Treasurer of Santa Fe Snyder Corporation from 1999 and in various capacities at Snyder Oil Corporation including Director Corporate Finance from 1998, Controller - SOCO Offshore, Inc., a wholly owned subsidiary, from 1997, and Accounting Manager from 1992. Mr. Swanson began his career with Apache Corporation in 1986 serving in internal audit and accounting.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Our common stock is listed and traded on the American Stock Exchange under the symbol "PLX". The number of stockholders of record of the common stock as of March 22, 2001 was 1,088.
The following table sets forth the range of high and low closing sales prices for the common stock as reported on the American Stock Exchange Composite Tape for the periods indicated below.
We have not paid cash dividends on shares of our common stock since our inception and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, we are restricted by provisions of the indentures governing the issue of $275.0 million 10.25% Senior Subordinated Notes Due 2006 (the "10.25% Notes") and prohibited by our $225.0 million revolving credit facility from paying dividends on our common stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA (IN THOUSANDS, EXCEPT FOR PER SHARE DATA)
The following selected historical financial information was derived from, and is qualified by reference to our consolidated financial statements, including the notes thereto, appearing elsewhere in this report. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and "Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
We are an independent energy company that is engaged in two related lines of business within the energy sector industry. Our first line of business, which we refer to as "upstream", acquires, exploits, develops, explores and produces crude oil and natural gas. Our second line of business, which we refer to as "midstream", is engaged in the marketing, transportation and terminalling of crude oil. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in PAA. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest.
RECENT DEVELOPMENTS
In connection with our business strategy, we continually review strategic options or proposals relating to mergers, consolidations and acquisition opportunities involving us and our subsidiaries. We have publicly announced that we are evaluating strategic restructuring alternatives intended to optimize the value and value-creating ability of each of our upstream and midstream business segments. The alternatives to be evaluated include, but are not limited to, a spin off or split off of the upstream segment or midstream segment, a spin off or special dividend of certain units of PAA and potential asset sales. Any modifications to the existing structure will depend on a number of factors including tax efficiency, critical mass and other considerations. Accordingly, there can be no assurance that any modifications will be made.
Consistent with our publicly announced intention to expand operations into Canada, we are pursuing the acquisition of certain Canadian assets in two separate transactions for aggregate consideration of approximately $200.0 million. See "Liquidity and Capital Resources - Recent Developments".
UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $174.0 million, which includes estimated associated costs and legal expenses. Approximately $7.1 million of this amount was recognized in 1998 and the remainder in 1999. In 2000, we recognized an additional $8.0 million charge for litigation related to the unauthorized trading losses. See Item 1. "Business - Unauthorized Trading Losses" for a discussion of the unauthorized trading loss, its financial effects and the steps taken to prevent future violations of PAA's trading policies. See Item 3. - "Legal Proceedings".
RESULTS OF OPERATIONS
In the fourth quarter of 2000, we adopted SAB 101. As a result, we record revenue from crude oil production in the period it is sold as opposed to when it is produced and carry any unsold production as inventory valued at historical cost. The total effect of implementing SAB 101 was to reduce reported sales volumes by 144,000 barrels for 2000 and net income by $175,000, including a $121,000 reduction for the cumulative effect of prior years. The effect of this change in accounting for crude oil inventories on prior periods is deminimus.
Also in the fourth quarter of 2000, we adopted EITF 99-19. Prior to this adoption, we reported the results of certain of our crude oil buy/sell and exchange activities on a net margin basis. Under EITF 99-19, we now report these activities as gross marketing, transportation, storage and terminalling revenues and expenses. Marketing, transportation, storage and terminalling revenues and expenses for all periods presented have been reclassified to reflect this adoption, with no effect on earnings.
Analysis of Three Years Ended December 31, 2000.
For the year ended December 31, 2000, we reported net income of $40.8 million, or $1.46 per share ($1.39 per diluted share) on total revenue of $6.6 billion as compared to a net loss of $25.3 million, or $2.05 per share on total revenue of $10.9 billion in 1999. For the year ended December 31, 1998, we reported a net loss of $62.3 million or $3.99 per share on total revenue of $3.6 billion.
The reported results for the years ended December 31, 2000, 1999 and 1998 include the following items:
. a $28.1 million gain on the sale of crude oil linefill; . a $20.1 million gain on the sale of the segment of the All American Pipeline that extends from Emidio, California, to McCamey, Texas; . $8.0 million charge for litigation related to the unauthorized trading losses; . $4.4 million of previously deferred net gains on interest rate swap terminations recognized due to the early extinguishment of debt; . a $5.0 million reserve for potentially uncollectible accounts receivable; . an extraordinary loss of $5.0 million related to the early extinguishment of debt (net of minority interest and tax benefit); . amortization of $4.6 million of debt issue costs associated with facilities put in place during the fourth quarter of 1999; . $2.7 million of noncash compensation expense; and . $0.9 million gain recognized upon the transfer of 69,444 of our units in PAA to employees of the general partner upon the vesting of transaction unit grants.
. $166.4 million of unauthorized trading losses; . a $16.5 million gain on the sale of crude oil linefill; . a $6.0 million after-tax gain ($9.8 million pre-tax) related to the sale of units by PAA; . restructuring expense of $1.4 million; . $1.0 million of noncash compensation expense; and . an extraordinary loss of $0.5 million related to the early extinguishment of debt (net of minority interest and tax benefit).
. $109.0 million after-tax ($173.9 million pre-tax) reduction in carrying cost of oil and natural gas properties due to low crude oil prices at December 31, 1998; . a $37.1 million after-tax ($60.8 million pre-tax) gain associated with the initial public offering of PAA; and . $7.1 million of unauthorized trading losses.
Excluding the items listed above, we would have reported net income of approximately $35.8 million and $18.2 million in 2000 and 1999, respectively. Adjusted EBITDA increased 25% in 2000 to $179.2 million from the $139.1 million reported in 1999 and 117% from the $80.3 million reported in 1998. Cash flow from operations (net income before noncash items), also excluding the items listed above, was $100.6 million, $70.4 million and $42.0 million in 2000, 1999 and 1998, respectively. Adjusted EBITDA also excludes the items discussed above.
Oil and natural gas sales. Oil and natural gas sales were $149.3 million in 2000, an increase of $33.1 million over 1999 due to higher product prices and increased production volumes which contributed approximately $28.7 million and $4.4 million to the increase, respectively. Oil and natural gas revenues increased to $116.2 million in 1999 as compared to $102.8 million in 1998 due to higher product prices and increased production volumes, which contributed approximately $7.5 million and $6.0 million to the increase, respectively.
Marketing, transportation, storage and terminalling revenues. Marketing, transportation, storage and terminalling revenues increased to $6.4 billion from $10.8 billion and $3.5 billion in 1999 and 1998, respectively. The decrease in 2000 as compared to 1999 was primarily attributable to lower buy/sell and exchange volumes associated with our gathering and marketing activities, partially offset by higher crude oil prices. The increase in 1999 as compared to 1998 was primarily due to increased volumes from our gathering and marketing activities, partially attributable to the May 1999 Scurlock acquisition, as well as higher crude oil prices. See "Midstream Results".
Gain on PAA unit offerings. In 1999, we recognized a pre-tax gain of $9.8 million ($6.0 million after-tax) in connection with PAA's October 1999 public offering. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of the units. We held approximate interests of 59% and 54% before and after this offering, respectively. During 1998, we recognized a pre- tax gain of approximately $60.8 million ($37.1 million after-tax) in connection with the formation of PAA. The gain was net of approximately $9.2 million of formation related expenses consisting primarily of amounts due to certain key employees in connection with the
successful formation of PAA, debt prepayment penalties and legal fees. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of units in the initial public offering. PAA may in the future issue additional units in public or private sales if it needs additional capital and if market conditions are favorable. Such sales could reduce our ownership in PAA and could generate additional gains.
Gain on sale of assets. In March 2000, we sold to a unit of El Paso for $129.0 million the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. Except for minor third-party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from the Goodyear Tire & Rubber Company in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove equipment. We used the proceeds from the sale to reduce the outstanding debt of PAA. We recognized a gain of approximately $20.1 million in connection with the sale.
We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized gains of approximately $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with the sale of the linefill.
Transaction grant gain. Upon the transfer of 69,444 of our units in PAA to employees of the general partner, a gain of $0.9 million was recognized in the first quarter of 2000, which represented the difference between the market price on the date of vesting and our basis in the units.
Production expenses. Total production expenses increased to $62.1 million from $55.6 million and $50.8 million in 1999 and 1998, respectively, primarily due to increased production volumes resulting from our acquisition and exploitation activities, as well as increased per unit costs.
Marketing, transportation, storage and terminalling expenses. Marketing, transportation, storage and terminalling expenses increased to $6.3 billion from $10.7 billion and $3.4 billion in 1999 and 1998, respectively, due to the reasons discussed above for marketing, transportation, storage and terminalling revenues.
Unauthorized trading losses. As previously discussed, we recognized losses of approximately $8.0 million, $166.4 million and $7.1 million in 2000, 1999 and 1998, respectively, as a result of unauthorized trading by a former employee. See "Unauthorized Trading Losses".
General and administrative. General and administrative expenses were $50.8 million for the year ended December 31, 2000, compared to $31.4 million and $10.8 million for 1999 and 1998, respectively. Our upstream and midstream activities accounted for approximately $2.1 million and $17.3 million, respectively, of the increase from 1999 to 2000 and $2.3 million and $18.3 million, respectively, of the increase from 1998 to 1999.
During 2000, a review of our accounts receivable indicated that certain amounts would not be collectible within one year. Accordingly, we reclassified approximately $10.0 million of accounts receivable from current assets to other assets. In addition, we recorded a $5.0 million charge to reserve for potentially uncollectible accounts receivable. During 2000 and 1999, we incurred charges of $2.7 million and $1.0 million, respectively, related to noncash incentive compensation paid to certain officers and key employees of Plains All American Inc. and its affiliates. In 1998 and 2000, Plains All American Inc. granted the employees the right to earn ownership in common units of PAA owned by Plains All American Inc. The units vest over a three-year period subject to PAA paying distributions on the common and subordinated units. These amounts are included in general and administrative expense on the Consolidated Statements of Operations and are attributable to the midstream segment.
Restructuring expense. A $1.4 million restructuring charge, primarily associated with severance-related expenses of 24 employees who were terminated, was incurred by PAA in 1999. Approximately $1.1 million of these costs are included in marketing, transportation, storage and terminalling expenses and approximately $0.3 million are included general and administrative expenses. As of December 31, 1999, all severance costs were paid and the terminated employees were not employed by PAA.
Depreciation, depletion and amortization. Total depreciation, depletion and amortization ("DD&A") was $47.2 million, $37.0 million and $31.0 million for the years ended December 31, 2000, 1999 and 1998, respectively. Our upstream and midstream activities accounted for approximately $2.9 million and $7.3 million, respectively, of the increase from 1999 to
2000. The $6.0 million increase from 1998 to 1999 is comprised of a $6.0 million decrease in upstream DD&A and a $12.0 million increase in midstream DD&A.
Reduction in carrying cost of oil and natural gas properties. In 1998, we incurred an impairment of our oil and natural gas properties due to low crude oil prices at December 31, 1998. Under full-cost accounting rules, unamortized costs of proved oil and natural gas properties are subject to a ceiling, which limits such costs. At December 31, 1998, the capitalized costs of our proved oil and natural gas properties exceeded this limit and we reduced the carrying cost of those properties by $109.0 million after tax ($173.9 million pre-tax).
Interest expense. Interest expense, net of capitalized interest, for 2000 increased to $55.8 million as compared to $46.4 million in 1999 and $35.7 million in 1998. The increase in 2000 is primarily due to increased interest rates. The increase in 1999 is due to (1) interest associated with the debt incurred for the Scurlock and West Texas Gathering System acquisitions, (2) interest for a full year on debt outstanding from the All American Pipeline acquisition, (3) an increase in interest related to hedged inventory transactions (4) higher debt levels related to our acquisition, exploitation, development and exploration activities and (5) higher interest rates. During 2000, 1999 and 1998, we capitalized $4.4 million, $4.4 million and $3.7 million of interest, respectively.
Provision (benefit) for income taxes. For the year ended December 31, 2000, we recognized a deferred tax provision of $24.6 million and a current tax provision of $1.0 million. For the year ended December 31, 1999, we recognized a deferred tax benefit of $20.5 million. For the year ended December 31, 1998, we recognized a deferred tax provision of $45.9 million and a current tax provision of $0.9 million. At December 31, 2000, we have a net deferred tax asset of $47.9 million, primarily attributable to net operating loss carryforwards. The minimum amount of future taxable income necessary to utilize the net operating loss carryforwards is $183.9 million. Based on current levels of pre-tax income, excluding nonrecurring items, management believes that it is more likely than not that we will generate taxable income from operations sufficient to realize the deferred tax asset.
Early extinguishment of debt. During 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $5.0 million (net of minority interest of $7.0 million and deferred tax of $3.2 million) related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of PAA's credit facilities. In addition, interest and other income for the year ended December 31, 2000 includes $4.4 million of previously deferred net gains from terminated interest rate swaps as a result of the debt extinguishment. The extraordinary item of $0.5 million (net of minority interest of $.07 million and deferred tax of $0.3 million) in 1999 relates to the write- off of certain debt issue costs and penalties associated with the prepayment of debt.
Upstream Results
The following table sets forth certain of our upstream operating information for the periods presented.
Upstream results were affected by of the adoption of SAB 101. As a result of SAB 101, we record revenue from crude oil production in the period it is sold as opposed to when it is produced and carry any unsold production as inventory valued at historical cost. The total effect of SAB 101 is to reduce reported sales volumes by 144,000 barrels for 2000 and net income for the year by $175,000, including a $121,000 reduction for the cumulative effect of prior years.
Total oil equivalent production increased approximately 3% to an average of 24,200 BOE per day from the 1999 level of 23,400 BOE per day and 10% above the 1998 level of 22,100 BOE per day. The volume increase in 2000 is attributable to a full year of production from the Point Arguello Unit, which we purchased from Chevron in July 1999. Current year production from this area was negatively impacted by approximately 400 BOE per day due to the reversion to a lower net revenue interest effective July 1, 2000. The volume increase in 1999 is primarily associated with our ongoing acquisition and exploitation activities, offset somewhat by decreased production from certain of our other properties. Net daily production from our onshore California properties averaged 15,400 BOE per day in 2000 compared to 15,600 BOE per day in 1999. The slight decrease is primarily due to natural decline. Net daily production for our Gulf Coast properties averaged approximately 1,900 BOE per day in 2000, compared to 2,600 BOE per day in 1999 and 4,800 BOE per day in 1998. The Gulf Coast production decrease is due to the effects of natural decline. Net daily production in the Illinois Basin averaged 2,800 BOE per day during 2000, compared to 3,000 BOE per day in 1999. The decrease is due to lower water injection rates, natural decline and the high demand for completion units which has delayed completion of newly drilled wells and routine well servicing.
Our product price averaged $16.85 per BOE in 2000, 24% and 33% higher than the price received in 1999 and 1998, respectively. Our product price represents a combination of fixed and floating price arrangements, typically tied to a benchmark price index and subjected to discounts for location and quality differentials. The price index is the NYMEX benchmark WTI crude oil price, which averaged $30.25 per barrel in 2000, $19.25 per barrel in 1999, and $14.43 per barrel in 1998. The discount to NYMEX for our crude oil production averaged $4.63 per barrel during 2000. Our average product prices also include the effects of hedging transactions such as financial swap and collar arrangements and futures transactions. These transactions had the effect of decreasing the overall average price we received (relative to the price we would have received in the absence of hedging) by $8.96 per BOE and $1.30 per BOE in 2000 and 1999, respectively, and increasing the price by $2.98 per BOE in 1998. We maintained hedges on approximately 82% of our crude oil production throughout 2000 at an average NYMEX WTI crude oil price of approximately $18.47 per barrel. We routinely hedge a portion of our crude oil production. See "Outlook" and Item 7a.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
We are exposed to various market risks, including volatility in crude oil commodity prices and interest rates. To manage our exposure, we monitor our inventory levels, current economic conditions and our expectations of future commodity prices and interest rates when making decisions with respect to risk management. We do not enter into derivative transactions for speculative trading purposes. Substantially all of our derivative contracts are exchanged or traded with major financial institutions and the risk of credit loss is considered remote.
Commodity Price Risk. The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a 10 percent price decrease are shown in the table below (in millions):
The fair values of the futures contracts are based on quoted market prices obtained from the NYMEX. The fair value of the swaps and option contracts are estimated based on quoted prices from independent reporting services compared to the contract price of the swap and approximate the gain or loss that would have been realized if the contracts had been closed out at year end. All hedge positions offset physical positions exposed to the cash market; none of these offsetting physical positions are included in the above table. Price-risk sensitivities were calculated by assuming an across-the-board 10 percent decrease in prices regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. In the event of an actual 10 percent change in prompt month crude oil prices, the fair value of our derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices.
We have entered into various arrangements, using a combination of swaps, collars and purchased puts and calls, to fix the NYMEX crude oil spot price for a significant portion of our crude oil production. On December 31, 2000, these arrangements provided for a NYMEX crude oil price of approximately $23.00 per barrel on 21,500 barrels per day from January 1, 2001, through December 31, 2001, with full market price participation up to an average of $27.00 per barrel. For 2002, we have entered into various arrangements that provide for us to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000 barrels per day with full market price participation up to an average of $24.90 per barrel. Location and quality differentials attributable to our properties and the cost of the hedges are not included in the foregoing prices. Because of the quality and location of our crude oil production, these adjustments will reduce our net price per barrel. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX price. Gains or losses are recognized in the month of related production and are included in crude oil and natural gas sales. Such contracts resulted in a reduction of revenues of $79.4 million and $11.1 million for the years ended December 31, 2000 and 1999, respectively. At December 31, 2000, we had an unrealized gain of $17.3 million with respect to such contracts.
At December 31, 2000, our hedging activities included crude oil futures contracts maturing through 2001, covering approximately 3.2 million barrels of crude oil. Because such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $15.1 million and $17.8 million for the years ended December 31, 2000 and 1999, respectively. The offsetting gains from the physical positions are not included in such amounts. The unrealized loss with respect to such instruments at December 31, 2000 was $7.8 million.
Interest Rate Risk. Our debt instruments are sensitive to market fluctuations in interest rates. The table below presents principal payments and the related weighted average interest rates by expected maturity dates for debt outstanding at December 31, 2000. Our variable rate debt bears interest at LIBOR or prime plus the applicable margin. The average interest rates presented below are based upon rates in effect at December 31, 2000. The carrying value of variable rate bank debt approximates fair value because interest rates are variable, based on prevailing market rates. The fair value of fixed rate debt was based on quoted market prices based on trades of subordinated debt. The fair value of the Redeemable Preferred Stock was based on a valuation provided by an outside source.
(1) After the February 2001 amendments to PAA's bank credit agreements, the expected year of maturity for $320.0 million of this amount is 2005.
At December 31, 1999, the carrying value of all variable rate bank debt and the Redeemable Preferred Stock of $506.1 million and $138.8 million, respectively, approximated the fair value and liquidation value, respectively, at that date. The carrying value and fair value of the fixed rate debt was $280.5 million and $268.1 million, respectively, at that date.
Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At December 31, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $240.0 million, for which we would pay approximately $0.9 million if such arrangements were terminated as of such date. The adjustment to interest expense resulting from interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.3 million gain and a $0.2 million loss, respectively. These instruments are based on LIBOR margins and provide for (1) a floor of 5% and a ceiling of 6.5% with an expiration date of February 2001 for $90.0 million notional principal amount (2) a floor of 6% and a ceiling of 8% with an expiration date of August 2002 for $125.0 million notional principal amount and (3) a ceiling of 5.7% with an expiration date of July 2008 for $25.0 million notional principal amount. The counterparty has the option to terminate the $25.0 million swap in July 2003, and either party may terminate in July 2005.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required here is included in the report as set forth in the "Index to Financial Statements" on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information regarding our directors will be included in the proxy statement for the 2001 annual meeting of stockholders (the "Proxy Statement") to be filed within 120 days after December 31, 2000, and is incorporated herein by reference. Information with respect to our executive officers is presented in Part I, Item 4 of this report.
ITEM 11.
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 regarding beneficial ownership 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) AND (2) FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES
See "Index to Consolidated Financial Statements" set forth on Page.
(A) (3) EXHIBITS
2.1 Stock Purchase Agreement dated as of March 15, 1998, among Plains Resources Inc., Plains All American Inc. and Wingfoot Ventures Seven Inc. (incorporated by reference to Exhibit 2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1997).
3.1 Second Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3(a) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995).
3.2 Bylaws of the Company, as amended to date (incorporated by reference to Exhibit 3(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
3.3 Certificate of Designation, Preference and Rights of Series D Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3(c) to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1997).
3.4 Certificate of Designation, Preference and Rights of Series F Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999).
3.5 Certificate of Designation, Preference and Rights of Series G Cumulative Convertible Preferred Stock (incorporated by reference to Exhibit 3(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999).
*3.6 Certificate of Designation, Preference and Rights of Series H Cumulative Convertible Preferred Stock.
4.1 Indenture dated as of March 15, 1996, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series A and Series B (incorporated by reference to Exhibit 4(b) to the Company's Form S-3 (Registration No. 333-1851)).
4.2 Indenture dated as of July 21, 1997, among the Company, the Subsidiary Guarantors named therein and Texas Commerce Bank National Association, as Trustee for the Company's 10 1/4% Senior Subordinated Notes due 2006, Series C and Series D (incorporated by reference to Exhibit 4 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997).
4.3 Specimen Common Stock Certificate (incorporated by reference to Exhibit 4 to the Company's Form S-1 Registration Statement (Reg. No. 33-33986)).
4.4 Purchase Agreement for Stock Warrant dated May 16, 1994, between Plains Resources Inc. and Legacy Resources, Co., L.P. (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1994).
4.5 Warrant dated November 12, 1997, to Shell Land & Energy Company for the purchase of 150,000 shares of Common Stock (incorporated by reference to Exhibit 4(d) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1997).
4.6 Indenture dated as of September 15, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein and Chase Bank of Texas, National Association, as Trustee (incorporated by reference to Exhibit 4(a) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
4.7 Registration Rights Agreement dated as of September 22, 1999, among Plains Resources Inc., the Subsidiary Guarantors named therein, J.P. Morgan Securities Inc. and First Union Capital Markets Corp. (incorporated by reference to Exhibit 4(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
4.8 Stock Purchase Agreement dated as of December 15, 1999, among Plains Resources Inc. and the purchasers named therein (incorporated by reference to Exhibit 4(g) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999).
4.9 Amendment to Stock Purchase Agreement dated as of December 17, 1999, among Plains Resources Inc. and the purchasers named therein (incorporated by reference to Exhibit 4(h) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999).
**10.1 Employment Agreement dated as of March 1, 1993, between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1993).
**10.2 The Company's 1991 Management Options (incorporated by reference to Exhibit 4.1 to the Company's Form S-8 Registration Statement (Reg. No. 33-43788)).
**10.3 The Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 4.3 to the Company's Form S-8 Registration Statement (Reg. No. 33-48610)).
**10.4 The Company's Amended and Restated 401(k) Plan (incorporated by reference to Exhibit 10(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996).
**10.5 The Company's 1996 Stock Incentive Plan (incorporated by reference to Exhibit 4 to the Company's Form S-8 Registration Statement (Reg. No. 333-06191)).
**10.6 Stock Option Agreement dated August 27, 1996 between the Company and Greg L. Armstrong (incorporated by reference to Exhibit 10(l) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996).
**10.7 Stock Option Agreement dated August 27, 1996 between the Company and William C. Egg Jr. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996).
**10.8 First Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1996).
**10.9 Second Amendment to the Company's 1992 Stock Incentive Plan (incorporated by reference to Exhibit 10(b) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1997).
10.10 Fourth Amended and Restated Credit Agreement dated May 22,1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(y) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1998).
**10.11 First Amendment to Plains Resources Inc. 1996 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(z) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998)
**10.12 Third Amendment to Plains Resources Inc. 1992 Stock Incentive Plan dated May 21, 1998 (incorporated by reference to Exhibit 10(aa) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1998).
10.13 First Amendment to Fourth Amended and Restated Credit Agreement dated as of November 17, 1998, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(m) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998).
10.14 Second Amendment to Fourth Amended and Restated Credit Agreement dated as of March 15, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(n) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998).
**10.15 Employment Agreement dated as of November 23, 1998, between Harry N. Pefanis and the Company (incorporated by reference to Exhibit 10(o) to the Company's Annual Report on Form 10-K for the year ended December 31, 1998).
10.16 Purchase and Sale Agreement dated June 4, 1999, by and among the Company, Chevron U.S.A., Inc., and Chevron Pipe Line Company (incorporated by reference to Exhibit 10(h) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999).
10.17 Third Amendment to Fourth Amended and Restated Credit Agreement dated June 21, 1999, among the Company and ING (U.S.) Capital Corporation, et. al. (incorporated by reference to Exhibit 10(p) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999).
10.18 Second Amendment to Plains Resources 1996 Stock Incentive Plan dated May 20, 1999 (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 1999).
10.19 Fourth Amendment to Fourth Amended and Restated Credit Agreement dated September 15, 1999, among the Company and First Union National Bank, et al. (incorporated by reference to Exhibit 10(q) to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 1999).
10.20 Fifth Amendment to Fourth Amended and Restated Credit Agreement dated December 1, 1999, among the Company and First Union National Bank, et al (incorporated by reference to Exhibit 10(t) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999).
10.21 Sixth Amendment to Fourth Amended and Restated Credit Agreement dated June 12, 2000, among the Company and First Union National Bank, et al (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2000).
10.22 Seventh Amendment to Fourth Amended and Restated Credit Agreement dated October 11, 2000, among the Company and First Union National Bank, et al (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2000).
*10.23 Third Amendment to Plains Resources 1996 Stock Incentive Plan dated June 7, 2000.
10.24 Forms of Officer Stock Option Agreement (incorporated by reference to Exhibits 4.1 and 4.2 to the Company's Form S-8 Registration Statement (Reg No. 333-45562)
10.25 Contribution, Conveyance and Assumption Agreement among Plains All American Pipeline, L.P. and certain other parties dated as of November 23, 1998 (incorporated by reference to Exhibit 10.03 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American, L.P.).
10.26 Plains All American Inc., 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.04 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).
10.27 Plains All American Inc., 1998 Management Incentive Plan (incorporated by reference to Exhibit 10.05 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).
10.28 Crude Oil Marketing Agreement among Plains Resources Inc., Plains Illinois Inc., Stocker Resources, L.P., Calumet Florida, Inc. and Plains Marketing, L.P. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.07 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).
10.29 Omnibus Agreement among Plains Resources Inc., Plains All American Pipeline, L.P., Plains Marketing, L.P., All American Pipeline, L.P., and Plains All American Inc. dated as of November 23, 1998 (incorporated by reference to Exhibit 10.08 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).
10.30 Transportation Agreement dated July 30, 1993, between All American Pipeline Company and Exxon Company, U.S.A. (incorporated by reference to Exhibit 10.9 to Registration Statement, file No. 333-64107 for Plains All American Pipeline, L.P.).
10.31 Transportation Agreement dated August 2, 1993, between All American Pipeline Company and Texaco Trading and Transportation Inc., Chevron U.S.A. and Sun Operating Limited Partnership (incorporated by reference to Exhibit 10.10 to Registration Statement, file No. 333- 64107 for Plains All American Pipeline, L.P.).
10.32 Form of Transaction Grant Agreement (Payment on Vesting) (incorporated by reference to Exhibit 10.12 to Registration Statement, file No. 333-64107 for Plains All American Pipeline, L.P.).
10.33 First Amendment to Contribution, Conveyance and Assumption Agreement dated as of December 15, 1998 (incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K for the Year Ended December 31, 1998 for Plains All American Pipeline, L.P.).
10.34 Agreement for Purchase and Sale of Membership Interest in Scurlock Permian LLC between Marathon Ashland LLC and Plains Marketing, L.P. dated as of March 17, 1999 (incorporated by reference to Exhibit
10.35 Asset Sales Agreement between Chevron Pipe Line Company and Plains Marketing, L.P. dated as of April 16, 1999 (incorporated by reference to Exhibit 10.17 to Quarterly Report on Form 10-Q for the Quarter Ended March 31, 1999 for Plains All American Pipeline, L.P.).
**10.36 Transaction Grant Agreement with Greg L. Armstrong (incorporated by reference to Exhibit 10.20 to Registration Statement on Form S-1, file no. 333-86907 1999 for Plains All American Pipeline, L.P.).
10.37 Pipeline Sale and Purchase Agreement dated January 31, 2000, among Plains All American Pipeline, L.P., All American Pipeline, L.P., El Paso Natural Gas Company and El Paso Pipeline Company (incorporated by reference to Exhibit 10.26 to Annual Report on Form 10-K for the Year Ended December 31, 1999 for Plains All American Pipeline, L.P.).
10.38 Credit Agreement [Letter of Credit and Hedged Inventory Facility] dated May 8, 2000, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders (incorporated by reference to Exhibit 10.01 to the Quarterly Report on Form 10-Q for Plains All American Pipeline, L.P. for the quarterly period ended March 31, 2000).
10.39 Credit Agreement [Revolving Credit Facility] dated May 8, 2000, among Plains Marketing, L.P., All American Pipeline, L.P., Plains All American Pipeline, L.P. and Fleet National Bank and certain other lenders (incorporated by reference to Exhibit 10.02 to the Quarterly Report on Form 10-Q for Plains All American Pipeline, L.P. for the quarterly period ended March 31, 2000).
10.40 First Amendment to Credit Agreement [Letter of Credit and Hedged Inventory Facility] dated as of February 26, 2001 (incorporated by reference to Exhibit 10.17 to Annual Report on Form 10-K for the Year Ended December 31, 2000 for Plains All American Pipeline, L.P.).
10.41 First Amendment to Credit Agreement [Revolving Credit Facility] dated as of February 26, 2001 (incorporated by reference to Exhibit 10.187 to Annual Report on Form 10-K for the Year Ended December 31, 2000 for Plains All American Pipeline, L.P.).
21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 21 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999) .
*23.1 Consent of PricewaterhouseCoopers LLP.
*23.2 Consent of H.J. Gruy and Associates, Inc.
*23.3 Consent of Netherland, Sewell and Associates, Inc.
*23.4 Consent of Ryder Scott Company.
- -------------- * Filed herewith ** A management contract or compensation plan.
(B) REPORTS ON FORM 8-K
A Current Report on Form 8-K was filed on December 7, 2000, in connection with our announcement that we would be evaluating strategic restructuring alternatives intended to optimize the value and value-creating ability of each of our upstream and midstream business segments.
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: April 2, 2001 By: /s/ Phillip D. Kramer --------------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Date: April 2, 2001 By: /s/ Greg L. Armstrong --------------------------------------------- Greg L. Armstrong, President, Chief Executive Officer and Director (Principal Executive Officer)
Date: April 2, 2001 By: /s/ Jerry L. Dees ---------------------------------------------- Jerry L. Dees, Director
Date: April 2, 2001 By: /s/ Tom H. Delimitros ---------------------------------------------- Tom H. Delimitros, Director
Date: April 2, 2001 By: /s/ Cynthia A. Feeback ---------------------------------------------- Cynthia A. Feeback, Vice President - Accounting And Assistant Treasurer (Principal Accounting Officer)
Date: April 2, 2001 By: /s/ William M. Hitchcock ----------------------------------------------- William M. Hitchcock, Director
Date: April 2, 2001 By: /s/ Phillip D. Kramer ---------------------------------------------- Phillip D. Kramer, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Date: April 2, 2001 By: /s/ Dan M. Krausse --------------------------------------------- Dan M. Krausse, Chairman of the Board and Director
Date: April 2, 2001 By: /s/ John H. Lollar --------------------------------------------- John H. Lollar, Director
Date: April 2, 2001 By: /s/ Robert V. Sinnott -------------------------------------------- Robert V. Sinnott, Director
Date: April 2, 2001 By: /s/ J. Taft Symonds -------------------------------------------- J. Taft Symonds, Director
Our annual report to stockholders for the year ended December 31, 2000, 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.
PLAINS RESOURCES INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
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, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, 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 our opinion.
As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for its crude oil inventories in connection with its adoption of Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements", effective January 1, 2000.
PricewaterhouseCoopers LLP
Houston, Texas March 22, 2001
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 OPERATIONS (IN THOUSANDS, EXCEPT 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 NON-REDEEMABLE PREFERRED STOCK, COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY (IN THOUSANDS)
See notes to consolidated financial statements.
PLAINS RESOURCES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 -- Organization and Basis of Presentation
Organization
We are an independent energy company that is engaged in two related lines of business. Our first line of business, which we refer to as "upstream", acquires, exploits, develops, explores and produces crude oil and natural gas. Our second line of business, which we refer to as "midstream", is engaged in the marketing, transportation and terminalling of crude oil. Terminals are facilities where crude oil is transferred to or from storage or a transportation system, such as a pipeline, to another transportation system, such as trucks or another pipeline. The operation of these facilities is called "terminalling". We conduct this second line of business through our majority ownership in Plains All American Pipeline, L.P. ("PAA"). Our upstream crude oil and natural gas activities are focused in California (in the Los Angeles Basin, the Arroyo Grande Field, and the Mt. Poso Field), California Outer Continental Shelf ("OCS") (in the Point Arguello Field), the Sunniland Trend of South Florida and the Illinois Basin in southern Illinois. Our midstream activities are concentrated in California, Texas, Oklahoma, Louisiana, Illinois and the Gulf of Mexico.
Basis of Consolidation and Presentation
The consolidated financial statements include the accounts of Plains Resources Inc., our wholly owned subsidiaries and PAA, in which we have an approximate 54% ownership interest. Plains All American Inc., one of our wholly owned subsidiaries, serves as PAA's sole general partner. For financial statement purposes, the assets, liabilities and earnings of PAA are included in our consolidated financial statements, with the public unitholders' interest reflected as a minority interest. All significant intercompany transactions have been eliminated. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.
Note 2 -- Summary of Significant Accounting Policies
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates made by management include (1) crude oil and natural gas reserves, (2) depreciation, depletion and amortization, including future abandonment costs, (3) income taxes and related valuation allowance, (4) allowance for doubtful accounts receivable and (5) accrued liabilities. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of three months or less. At December 31, 2000 and 1999, the majority of cash and cash equivalents is concentrated in two institutions and at times may exceed federally insured limits. We periodically assess the financial condition of the institutions and believe that any possible credit risk is minimal.
Accounts Receivable, Net. At December 31, 2000, our allowance for doubtful accounts receivable totaled $5.0 million and is reflected in the consolidated balance sheet as a reduction of certain accounts receivable which are included in Other Assets. The allowance was established in 2000 by a $5.0 million charge to general and administrative expense.
Inventory. Crude oil inventories related to oil and gas producing operations are carried at cost. Crude oil inventories related to marketing, transportation, storage and terminalling operations are 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 an average cost method.
Inventory consists of the following (in thousands):
Oil and Natural Gas Properties. We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration, exploitation and development activities are capitalized. Such costs include internal general and administrative costs such as payroll and related benefits and costs directly attributable to employees engaged in acquisition, exploration, exploitation and development activities. General and administrative costs associated with production, operations, marketing and general corporate activities are expensed as incurred. These capitalized costs along with our estimate of future development and abandonment costs, net of salvage values and other considerations, are amortized to expense by the unit-of-production method using engineers' estimates of unrecovered proved oil and natural gas reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. Proceeds from the sale of oil and natural gas properties are accounted for as reductions to capitalized costs unless such sales involve a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized. Unamortized costs of proved properties are subject to a ceiling which limits such costs to the present value of estimated future cash flows from proved oil and natural gas reserves of such properties reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values), and estimated future income taxes thereon (the "Standardized Measure") (see Note 20).
Crude Oil Pipeline, Gathering and Terminal Assets. Crude oil pipeline, gathering and terminal assets are recorded at cost. Depreciation is computed using the straight-line method over estimated useful lives as follows:
. crude oil pipelines - 40 years;
. crude oil pipeline facilities - 25 years;
. crude oil terminal and storage facilities - 30 to 40 years; and
. trucking equipment, injection stations and other - 5 to 10 years.
Acquisitions and improvements are capitalized; maintenance and repairs are expensed as incurred.
Other Property and Equipment. Other property and equipment is recorded at cost and consists primarily of office furniture and fixtures and computer hardware and software. Acquisitions, renewals, and betterments are capitalized; maintenance and repairs are expensed. Depreciation is provided using the straight-line method over estimated useful lives of three to seven years. Net gains or losses on property and equipment disposed of are included in interest and other income in the period in which the transaction occurs.
Other Assets. Other assets consist of the following (in thousands):
Costs incurred in connection with the issuance of long-term debt are capitalized and amortized using the straight-line method over the term of the related debt. Use of the straight-line method does not differ materially from the "effective interest" method of amortization.
Pipeline Linefill. Pipeline linefill is recorded at cost and consists of crude oil linefill used to pack a pipeline such that when an incremental barrel enters a pipeline it forces a barrel out at another location. At December 31, 2000, we had approximately 1.6 million barrels of crude oil used to maintain our minimum operating linefill requirements. Proceeds from the sale and repurchase of pipeline linefill are reflected as cash flows from operating activities in the accompanying consolidated statements of cash flows. Proceeds from the sale of 5.2 million barrels of crude oil linefill in connection with the segment of the All American Pipeline that we sold are included in investing activities in the accompanying consolidated statements of cash flows (see Note 6).
Federal and State Income Taxes. Income taxes are accounted for in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes ("SFAS 109"). SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax bases of assets and liabilities using tax rates in effect for the year in which the differences are expected to reverse.
Revenue Recognition. Gathering and marketing revenues are accrued at the time title to the product sold transfers to the purchaser, which occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to us, which occurs upon our receipt of the product. Terminalling and storage revenues are recognized at the time service is performed. Revenues for the transportation of crude oil are recognized based upon regulated and non-regulated tariff rates and the related transported volumes.
Oil and gas revenue from our interests in producing wells is recognized when the production volumes are sold. Transportation costs incurred in connection with such operations, which are immaterial, are reflected as a reduction of sales revenues.
Hedging. We utilize various derivative instruments, for purposes other than trading, to hedge our exposure to price fluctuations on crude in storage and expected purchases, sales and transportation of crude oil. The derivative instruments consist primarily of futures and option contracts traded on the New York Mercantile Exchange and crude oil swap contracts entered into with financial institutions. We also utilize interest rate swaps and collars to manage the interest rate exposure on our long-term debt.
These derivative instruments qualify for hedge accounting as they reduce the price risk of the underlying hedged item and are designated as a hedge at inception. Additionally, the derivatives result in financial impacts that are inversely correlated to those of the items being hedged. This correlation, generally in excess of 80%, (a measure of hedge effectiveness) is measured both at the inception of the hedge and on an ongoing basis. If correlation ceases to exist, we would discontinue hedge accounting and apply mark to market accounting. Gains and losses on the termination of hedging instruments are deferred and recognized in income as the impact of the hedged item is recorded.
Unrealized changes in the market value of crude oil hedge contracts are not generally recognized in our statement of operations until the underlying hedged transaction occurs. The financial impacts of crude oil hedge contracts are included in our statements of operations as a component of revenues. Such financial impacts are offset by gains or losses realized in the physical market. Cash flows from crude oil hedging activities are included in operating activities in the accompanying statements of cash flows. Net deferred gains and losses on futures contracts, including closed futures contracts, entered into to hedge anticipated crude oil purchases and sales, are included in current assets or current liabilities in the accompanying balance sheets. Deferred gains or losses from inventory hedges are included as part of the inventory costs and recognized when the related inventory is sold.
Amounts paid or received from interest rate swaps and collars are charged or credited to interest expense and matched with the cash flows and interest expense of the long-term debt being hedged, resulting in an adjustment to the effective interest rate.
Stock Options. We have elected to follow Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees ("APB 25") and related interpretations in accounting for our employee stock options. Under APB 25, no compensation expense is recognized when the exercise price of options equals the fair value (market price) of the underlying stock on the date of grant.
Sale of Units by a Subsidiary. When a subsidiary sells additional units to a third party, resulting in a change in our percentage ownership interest, we recognize a gain or loss in our consolidated statement of operations if the selling price per unit is more or less than our average carrying amount per unit. When we buy additional units from a subsidiary, resulting in a change in our percentage ownership interest, the difference between our cost and underlying equity in investee net assets is assigned first to identifiable tangible and intangible assets and to liabilities based on their fair values at the date of the change of interest; any unassigned difference is assigned to goodwill.
Recent Accounting Pronouncements. In the fourth quarter of 2000, we adopted Securities and Exchange Commission ("SEC") Staff Accounting Bulletin 101, "Revenue Recognition in Financial Statements" ("SAB 101"). As a result, we record revenue from crude oil production in the period it is sold as opposed to when it is produced and carry any unsold production as inventory valued at historical cost. The total effect of implementing SAB 101 was to reduce reported sales volumes by 144,000 barrels for 2000 and net income for the year by $175,000, including a $121,000 reduction for the cumulative effect of prior years. The effect of this change in accounting for crude oil inventories on prior periods was deminimus.
We implemented Emerging Issues Task Force ("EITF") Issue No. 99-19, "Recording Revenue Gross as a Principal versus Net as an Agent" in the fourth quarter of 2000. Crude oil buy/sell contracts and exchanges whereby like volumes are purchased and sold were previously reported net in cost of sales and operations. These transactions have been reclassified to be reflected as gross in marketing, transportation, storage and terminalling revenues and expenses in our statements of operations for all periods presented, with no effect on earnings. The amounts by which revenues and expenses have been reclassified for the years ended December 31, 2000 and 1999 and 1998 are $2.5 billion, $6.2 billion and 2.3 billion, respectively.
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS 133. SFAS 133 was subsequently amended (i) in June 1999 by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" ("SFAS 137"), which deferred the effective date of SFAS 133 to fiscal years beginning after June 15, 2000; and (ii) in June 2000 by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedge Activities," which amended certain provisions, inclusive of the definition of the normal purchase and sale exclusion. We have determined that our physical purchase and sale agreements, which under SFAS 133 could be considered derivatives, qualify for the normal purchase and sale exclusion.
SFAS 133 requires that all derivative instruments be recorded on the balance sheet at their fair value. Changes in the fair value of derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if so, the type of hedge transaction. For fair value hedge transactions in which we are hedging changes in the fair value of an asset, liability, or firm commitment, changes in the fair value of the derivative instrument will generally be offset in the income statement by changes in the fair value of the hedged item. For cash flow hedge transactions, in which we are hedging the variability of cash flows related to a variable-rate asset, liability, or a forecasted transaction, changes in the fair value of the derivative instrument will be reported in other comprehensive income. The gains and losses on the derivative instrument that are reported in other comprehensive income will be reclassified as earnings in the periods in which earnings are affected by the variability of the cash flows of the hedged item. The ineffective portion of all hedges will be recognized in earnings in the current period.
We have adopted SFAS 133, as amended, effective January 1, 2001. Our implementation procedures identified all instruments in place at the adoption date that are subject to the requirements of SFAS 133. Upon adoption, we recorded a net-of-tax and minority interest cumulative effect gain of $4.5 million in other comprehensive income and a net-of-tax and minority interest cumulative effect charge of $2.0 million to earnings to recognize at fair value all derivative instruments that were designated as cash flow hedging instruments. Correspondingly, assets have been increased by $14.2 million and liabilities and minority interest have been increased by $11.7 million. Implementation issues continue to be addressed by the FASB and any change to existing guidance might impact our implementation. Adoption of this standard could increase volatility in earnings and equity through comprehensive income.
NOTE 3 -- UNAUTHORIZED TRADING LOSSES
In November 1999, we discovered that a former employee of PAA had engaged in unauthorized trading activity, resulting in losses of approximately $174.0 million, which includes estimated associated costs and legal expenses. Approximately $7.1 million of the unauthorized trading losses were recognized in 1998 and the remainder in 1999. In 2000, we recognized an additional $8.0 million charge for litigation related to the unauthorized trading losses (see Note 17).
NOTE 4 -- PLAINS ALL AMERICAN PIPELINE, L.P. - FORMATION AND OFFERINGS
Our midstream activities are conducted through PAA. PAA was formed in September of 1998 to acquire and operate the business and assets of our wholly owned midstream subsidiaries.
On November 23, 1998, PAA completed an initial public offering of 13,085,000 common units at $20.00 per unit, representing limited partner interests and received proceeds of approximately $244.7 million. Concurrently with the closing of the initial public offering, certain of our midstream subsidiaries were merged into Plains Resources Inc., and then we sold the assets of these subsidiaries to PAA in exchange for $64.1 million and the assumption of $11.0 million of related
indebtedness. At the same time, the general partner conveyed all of its interest in the All American Pipeline and the SJV Gathering System to PAA in exchange for:
. 6,974,239 common units, 10,029,619 subordinated units and an aggregate 2% general partner interest;
. the right to receive incentive distributions as defined in the partnership agreement; and
. PAA's assumption of $175.0 million of indebtedness incurred by the general partner in connection with the acquisition of the All American Pipeline and the SJV Gathering System.
In addition to the $64.1 million paid to us, PAA distributed approximately $177.6 million to the general partner and used approximately $3.0 million of the remaining proceeds to pay expenses incurred in connection with the offering. The general partner used $121.0 million of the cash distributed to it to retire the remaining indebtedness incurred in connection with the acquisition of the All American Pipeline and the SJV Gathering System and to pay other costs associated with the transactions. The general partner distributed the remaining $56.6 million to us, which we used to repay indebtedness and for other general corporate purposes.
During 1998, we recognized a pre-tax gain of approximately $60.8 million ($37.1 million after-tax) in connection with the formation of PAA. The gain was net of approximately $9.2 million of formation related expenses consisting primarily of amounts due to certain key employees in connection with the successful formation of PAA, debt prepayment penalties and legal fees. The gain is the result of an increase in the book value of our equity in PAA to reflect our proportionate share of the underlying net assets of PAA due to the sale of units in the initial public offering.
In May 1999, PAA sold to the general partner 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.25 per unit, the price equal to the market value of PAA's common units on May 12, 1999, in connection with the Scurlock acquisition (see Note 6).
In October 1999, PAA completed a public offering of an additional 2,990,000 common units representing limited partner interests, at $18.00 per unit. Net proceeds to PAA from the offering, including our general partner contribution of $0.5 million, were approximately $51.3 million after deducting underwriters' discounts and commissions and offering expenses of approximately $3.1 million. These proceeds were used to reduce outstanding debt. We recognized a pre-tax gain of $9.8 million ($6.0 million after-tax) in connection with the offering as a result of an increase in the book value of our equity in PAA, as discussed above. We held approximate interests of 59% and 54% before and after PAA's secondary offering, respectively.
NOTE 5 -- UPSTREAM ACQUISITIONS
On July 1, 1999, Arguello Inc., our wholly owned subsidiary, acquired Chevron's interests in Point Arguello for approximately $1.0 million. The interests acquired include Chevron's 26% working interest in the Point Arguello Unit, its 26% interest in various partnerships owning the associated transportation, processing and marketing infrastructure, and Chevron's right to participate in surrounding leases and certain fee acreage onshore. We assumed its 26% share of (1) plugging and abandoning all existing well bores, (2) removing conductors, (3) flushing hydrocarbons from all lines and vessels and (4) removing/abandoning all structures, fixtures and conditions created subsequent to closing. Chevron retained the obligation for all other abandonment costs, including but not limited to (1) removing, dismantling and disposing of the existing offshore platforms, (2) removing and disposing of all existing pipelines and (3) removing, dismantling, disposing and remediation of all existing onshore facilities.
During 1998, we acquired the Mt. Poso field from Aera Energy LLC for approximately $7.7 million. The field is located approximately 27 miles north of Bakersfield, California, in Kern County. The field added approximately 8 million barrels of oil equivalent to our proved reserves at the acquisition date.
NOTE 6 -- MIDSTREAM ACQUISITIONS AND DISPOSITIONS
Scurlock Acquisition
On May 12, 1999, PAA completed the acquisition of Scurlock Permian LLC and certain other pipeline assets from Marathon Ashland Petroleum LLC. Including working capital adjustments and closing and financing costs, the cash purchase price was approximately $141.7 million.
Financing for the Scurlock acquisition was provided through:
. borrowings of approximately $92.0 million under a previous bank facility;
. the sale to the general partner of 1.3 million Class B common units of PAA for a total cash consideration of $25.0 million, or $19.125 per unit, the price equal to the market value of PAA's common units on May 12, 1999; and
. a $25.0 million draw under PAA's existing revolving credit agreement.
The funds for the purchase of the Class B units by the general partner were provided by a capital contribution from us. We financed our capital contribution through our revolving credit facility.
The assets, liabilities and results of operations of Scurlock are included in our consolidated financial statements effective May 1, 1999. The Scurlock acquisition has been accounted for using the purchase method of accounting and the purchase price was allocated in accordance with Accounting Principles Board Opinion No. 16, Business Combinations ("APB 16") as follows (in thousands):
Pro Forma Results for the Scurlock Acquisition
The following unaudited pro forma data is presented to show pro forma revenues, net loss and basic and diluted net loss per share as if the Scurlock acquisition, which was effective May 1, 1999, had occurred on January 1, of each year presented (in thousands, except per share data):
West Texas Gathering System Acquisition
On July 15, 1999, PAA completed the acquisition of a West Texas crude oil pipeline and gathering system from Chevron Pipe Line Company for approximately $36.0 million, including transaction costs. Our total acquisition cost was approximately $38.9 million including costs to address certain issues identified in the due diligence process. The principal assets acquired include approximately 450 miles of crude oil transmission mainlines, approximately 400 miles of associated gathering and lateral lines and approximately 2.9 million barrels of crude oil storage and terminalling capacity in Crane, Ector, Midland, Upton, Ward and Winkler Counties, Texas. Financing for the amounts paid at closing was provided by a draw under the term loan portion of a previous credit facility of PAA.
All American Pipeline Acquisition
On July 30, 1998, Plains All American Inc., acquired all of the outstanding capital stock of the All American Pipeline Company, Celeron Gathering Corporation and Celeron Trading & Transportation Company (collectively the ''Celeron Companies'') from Wingfoot, a wholly owned subsidiary of the Goodyear Tire and Rubber Company ("Goodyear") for approximately $400.0 million, including transaction costs. The principal assets of the entities acquired include the All American Pipeline and the SJV Gathering System, as well as other assets related to such operations. The acquisition was accounted for utilizing the purchase method of accounting with the assets, liabilities and results of operations included in our consolidated financial statements effective July 30, 1998.
The acquisition was accounted for utilizing the purchase method of accounting and the purchase price was allocated in accordance with APB 16 as follows (in thousands):
Financing for the acquisition was provided through a $325.0 million, limited recourse bank facility and an approximate $114.0 million capital contribution by us. Actual borrowings at closing were $300.0 million.
Pro Forma Results for the All American Pipeline Acquisition
The following unaudited pro forma data is presented to show pro forma revenues, net loss and basic and diluted net loss per share as if the All American Pipeline acquisition had occurred on January 1, 1998 (in thousands, except per share data):
All American Pipeline Linefill Sale and Asset Disposition
In March 2000, we sold to a unit of El Paso Corporation for $129.0 million the segment of the All American Pipeline that extends from Emidio, California to McCamey, Texas. Except for minor third-party volumes, one of our subsidiaries, Plains Marketing, L.P., was the sole shipper on this segment of the pipeline since its predecessor acquired the line from Goodyear in July 1998. We realized net proceeds of approximately $124.0 million after the associated transaction costs and estimated costs to remove some equipment. We used the proceeds from the sale to reduce the outstanding debt of PAA. We recognized a gain of approximately $20.1 million in connection with the sale. The cost of the pipeline segment is included in assets held for sale on the consolidated balance sheet at December 31, 1999.
We had suspended shipments of crude oil on this segment of the pipeline in November 1999. At that time, we owned approximately 5.2 million barrels of crude oil in the segment of the pipeline. We sold this crude oil from November 1999 to February 2000 for net proceeds of approximately $100.0 million, which were used for working capital purposes. We recognized gains of approximately $28.1 million and $16.5 million in 2000 and 1999, respectively, in connection with the sale of the linefill. The amount of crude oil linefill for sale at December 31, 1999 was $37.9 million and is included in assets held for sale on the consolidated balance sheet.
Note 7 -- Long-Term Debt and Credit Facilities
Short-term debt and current portion of long-term debt consists of the following (in thousands):
Long-term debt consists of the following (in thousands):
PLAINS RESOURCES LONG-TERM DEBT AND CREDIT FACILITIES
Revolving Credit Facility
We have a $225.0 million revolving credit facility with a group of banks. The revolving credit facility is guaranteed by all of our upstream subsidiaries and is collateralized by our upstream oil and natural gas properties and those of the guaranteeing subsidiaries and the stock of all the upstream subsidiaries. The borrowing base under the revolving credit facility at December 31, 2000, is $225.0 million and is subject to redetermination from time to time by the lenders in good faith, in the exercise of the lenders' sole discretion, and in accordance with customary practices and standards in effect from time to time for crude oil and natural gas loans to borrowers similar to our company. Our borrowing base may be affected from time to time by the performance of our oil and natural gas properties and changes in oil and natural gas prices. We incur a commitment fee of 3/8% per annum on the unused portion of the borrowing base. In addition, we pay a fee of 1 3/8% per annum of the face amount of letters of credit that are issued under our revolving credit facility. The revolving credit facility, as amended, terminates on July 1, 2002, at which time the remaining outstanding balance converts to a term loan which is repayable in twelve equal quarterly installments commencing October 1, 2002, with a final maturity of July 1, 2005. The revolving credit facility bears interest, at our option, of either LIBOR plus 1 3/8% or Base Rate (as defined therein). At December 31, 2000, letters of credit of $0.6 million were outstanding under the revolving credit facility.
The revolving credit facility contains covenants which, among other things, prohibit the payment of cash dividends on common stock, limit repurchases of common stock, limit the amount of consolidated debt, limit our ability to make certain loans and investments and provide that we must maintain a specified relationship between current assets and current liabilities. We are currently in compliance with the covenants contained in the revolving credit facility. At December 31, 2000, we could have borrowed the full $225.0 million available under the revolving credit facility.
10.25% Senior Subordinated Notes Due 2006
We have $275.0 million principal amount of 10.25% Senior Subordinated Notes Due 2006 outstanding, bearing a coupon rate of 10.25%, which at December 31, 2000 consists of (in thousands):
The Series A and Series B 10.25% Notes were issued in 1996 at 99.38% of par to yield 10.35%. The Series C and Series D 10.25% Notes were issued in 1997 at approximately 107% of par. The Series E 10.25% Notes were issued in September 1999 pursuant to a Rule 144A private placement at approximately 101% of par. Proceeds from the sale of the Series E 10.25% Notes, net of offering costs, were approximately $74.6 million and were used to reduce the balance on our revolving credit facility.
The 10.25% Notes are redeemable, at our option, on or after March 15, 2001 at 105.13% of the principal amount thereof, at decreasing prices thereafter prior to March 15, 2004, and thereafter at 100% of the principal amount thereof plus, in each case, accrued interest to the date of redemption.
The Indenture contains covenants that include, but are not limited to, covenants that: (1) limit the incurrence of additional indebtedness; (2) limit certain investments; (3) limit restricted payments; (4) limit the disposition of assets; (5) limit the payment of dividends and other payment restrictions affecting subsidiaries; (6) limit transactions with affiliates; (7) limit the creation of liens; and (8) restrict mergers, consolidations and transfers of assets. In the event of a Change of Control and a corresponding Rating Decline, as both are defined in the Indenture, we will be required to make an offer to repurchase the 10.25% Notes at 101% of the principal amount thereof, plus accrued and unpaid interest to the date of the repurchase.
The Series A-E Notes are unsecured general obligations and are subordinated in right of payment to all our existing and future senior indebtedness and are guaranteed by all of our upstream subsidiaries on a full, unconditional, joint and several basis. The Series A-E Notes are not guaranteed by PAA or any of our other midstream subsidiaries (see Note 24).
On March 13, 2001, we exchanged the $75.0 million principal amount of Series E Notes for 10.25% Senior Subordinated Notes due 2006, Series F. The Series F Notes are substantially identical (including principal amount, interest rate, maturity and redemption rights) to the Series E Notes for which they were exchanged, except for certain transfer restrictions relating to the Series E Notes.
PLAINS ALL AMERICAN PIPELINE L.P. CREDIT FACILITIES
The discussion below relates to credit facilities of PAA, which are nonrecourse to us, but are included in our consolidated financial statements. In addition, our indirect ownership in PAA does not collateralize any of our credit facilities.
At December 31, 2000, PAA's bank credit agreements consist of:
. a $400.0 million senior secured revolving credit facility. The revolving credit facility is secured by substantially all of PAA's assets and matures in April 2004. No principal is scheduled for payment prior to maturity. The revolving credit facility bears interest at PAA's option at either the base rate, as defined, plus an applicable margin, or LIBOR plus an applicable margin. PAA incurs a commitment fee of 0.25% to 0.5% on the unused portion of the revolving credit facility.
. a $300.0 million senior secured letter of credit and borrowing facility, the purpose of which is to provide standby letters of credit to support the purchase and exchange of crude oil for resale and borrowings to finance crude oil inventory that has been hedged against future price risk. The letter of credit facility is secured by substantially all of PAA's assets and has a sublimit for cash borrowings of $100.0 million to purchase crude oil that has been hedged against future price risk. The letter of credit facility expires in April 2003. Aggregate availability under the letter of credit facility for direct borrowings and letters of credit is limited to a borrowing base that is determined monthly based on certain of PAA's current assets and current liabilities (primarily inventory and accounts receivable and accounts payable related to the purchase and sale of crude oil). At December 31, 2000, approximately $59.7 million in letters of credit were outstanding under the letter of credit and borrowing facility.
PAA's bank credit agreements prohibit distributions on, or purchases or redemptions of, units if any default or event of default is continuing. In addition, the agreements contain various covenants limiting PAA's ability to, among other things:
. incur indebtedness;
. grant liens;
. sell assets;
. make investments;
. engage in transactions with affiliates;
. enter into prohibited contracts; and
. enter into a merger or consolidation.
PAA's bank credit agreements treat a change of control as an event of default and also require PAA to maintain:
. a current ratio (as defined) of 1.0 to 1.0;
. a debt coverage ratio that is not greater that 4.0 to 1.0 for the period from March 31, 2000 to March 31, 2002 and subsequently 3.75 to 1.0;
. an interest coverage ratio that is not less than 2.75 to 1.0; and
. a debt to capital ratio of not greater than 0.65 to 1.0.
A default under PAA's bank credit agreements would permit the lenders to accelerate the maturity of the outstanding debt and to foreclose on the assets securing the credit facilities. As long as PAA is in compliance with its bank credit agreements, they do not restrict its ability to make distributions of "available cash" as defined in their partnership agreement. PAA is currently in compliance with the covenants contained in its credit agreements. At December 31, 2000, PAA could have borrowed the up to $386.4 million under its secured revolving credit facility.
In February 2001, PAA's bank credit agreements were amended. The amount available under the senior secured revolving credit facility was increased to $500.0 million and the maturity date was extended to April 2005. The amount available under the senior secured letter of credit and borrowing facility was reduced to $200.0 million and the expiration date was extended to April 2004. In addition, the banks agreed to an amendment which will allow PAA to borrow an additional $130.0 million under the terms of the senior secured revolving credit facility. PAA has an underwritten commitment, subject to conditions, for the $130.0 million.
In December 1999, we loaned PAA $114.0 million for working capital requirements created by the 1999 unauthorized trading losses (see Note 3). This loan was repaid in May 2000 with proceeds from PAA's senior secured revolving credit facility.
On December 30, 1999, PAA entered into a $65.0 million senior secured term credit facility to fund short-term working capital requirements resulting from the unauthorized trading losses. The facility was secured by a portion of the 5.2 million barrels of linefill that was sold and receivables from certain sales contracts applicable to the linefill. The facility had a maturity date of March 24, 2000 and was repaid with the proceeds from the sale of the linefill securing the facility.
At December 31, 1999 PAA had a $225.0 million bank credit agreement that included a $175.0 million term loan facility and a $50.0 million revolving credit facility. As a result of the unauthorized trading losses discovered in November 1999, the facility was in default of certain covenants, with those defaults being subsequently waived and the facility amended in December. At December 31, 1999, PAA had $225.0 million outstanding under the terms of this bank credit facility. In addition, at December 31, 1999, Plains Scurlock had a bank credit agreement which consisted of a five-year $82.6 million term loan facility and a three-year $35.0 million revolving credit facility. The revolving credit facility could be used for borrowings or letters of credit to support crude oil purchases. As of December 31, 1999, letters of credit of approximately $29.5 million were outstanding under the revolver and borrowings of $82.6 million and $2.5 million were outstanding under the term loan and revolver, respectively. Amounts outstanding under these credit agreements were repaid in May 2000 with proceeds from PAA's senior secured revolving credit facility.
Maturities
The aggregate amount of maturities of all long-term indebtedness for the next five years is: 2001 - $0.5 million, 2002 - $2.8 million, 2003 - $9.6 million, 2004 - $329.6 million and 2005 - $6.8 million. After the February 2001 amendments to PAA's credit agreements, the maturities were: 2001 - $0.5 million, 2002 - $2.8 million, 2003 - $9.6 million, 2004 - $9.6 million and 2005 - $326.8 million.
NOTE 8 - REDEEMABLE PREFERRED STOCK
Liquidation Preference
All series of our cumulative convertible preferred stock are stated at liquidation preference on the consolidated balance sheet. Liquidation preference represents the number of shares outstanding, which includes cumulative noncash dividends, multiplied by the stated value of the shares. Any unpaid cash dividends are accrued in accounts payable and other current liabilities on the consolidated balance sheet. We have no current intention of redeeming the cumulative preferred stock before its mandatory redemption date. However, we review our capital structure regularly and may redeem shares of our preferred stock if future conditions warrant.
Series E and Series G Cumulative Convertible Preferred Stock
In connection with the sale of the Series F Preferred Stock described below, we agreed with the purchasers of our Series F Preferred Stock (who were also holders of the Series E Preferred Stock), to reduce the conversion price of the Series E Preferred Stock from $18.00 to $15.00. This reduction of the conversion price of the Series E Preferred Stock was effected through an exchange of each outstanding share of Series E Preferred Stock for a share of a new Series G Preferred Stock on February 1, 2000. Other than the reduction of the conversion price, the terms of the Series G Preferred Stock were substantially identical to those of the Series E Preferred Stock.
In December 2000, we exchanged or redeemed all of the shares of Series G Preferred Stock that had not been previously converted into shares of common stock. We exchanged 169,571 shares of Series G Preferred Stock for 169,571 shares of our Series H Preferred Stock (see Note 9) and in connection therewith paid $2.0 million, the amount equal to accrued dividends, and converted 1,825 shares of Series G Preferred Stock into 62,226 shares of common stock. The remaining 213 shares of the Series G Preferred Stock were redeemed at 105% of stated value in accordance with the original terms. In connection with that redemption, we paid $114,000 consisting of $112,000 for stated value and $2,000 for accrued and unpaid dividends. In 2000, we paid cash dividends of approximately $8.4 million on the Series G Preferred Stock for the period from October 1, 1999 through September 30, 2000.
The Series E Cumulative Convertible Preferred Stock (the "Series E Preferred Stock") was sold in a private placement on July 29, 1998 for $85.0 million. Each share of the Series E Preferred Stock had a stated value of $500 per share and bore a dividend of 9.5% per annum. Dividends were payable semi-annually in either cash or additional shares of Series E Preferred Stock at our option and were cumulative from the date of issue. Each share of Series E Preferred Stock was convertible into 27.78 shares of common stock (an initial effective conversion price of $18.00 per share) and in certain circumstances was convertible at our option into common stock if the average trading price for any thirty-day trading period is equal to or greater than $21.60 per share. Proceeds from the Series E preferred Stock were used to fund a portion of our capital contribution to Plains All American Inc. to acquire the Celeron Companies (see Note 6). At December 31, 1999, there were 177,626 shares outstanding.
Series F Cumulative Convertible Preferred Stock
On December 14, 1999, we sold in a private placement 50,000 shares of our Series F Cumulative Convertible Preferred Stock (the "Series F Preferred Stock") for $50.0 million. Each share of the Series F Preferred Stock has a stated value of $1,000 per share and bears a dividend of 10% per annum. Dividends are payable semi-annually in either cash or additional shares of Series F Preferred Stock at our option and are cumulative from the date of issue. Dividends paid in additional shares of Series F Preferred Stock are limited to an aggregate of six dividend periods. Each share of Series F Preferred Stock is convertible into 81.63 shares of common stock (an initial effective conversion price of $12.25 per share) and in certain circumstances may be converted at our option into common stock if the average trading price for any sixty-day trading period is equal to or greater than $21.60 per share. After December 15, 2003, the Series F Preferred Stock is redeemable at our option at 110% of stated value through December 15, 2004 and at declining amounts thereafter. If not previously redeemed or converted, the Series F Preferred Stock is required to be redeemed in 2007. At December 31, 2000 and 1999, there were 50,000 shares outstanding.
Proceeds from the Series F Preferred Stock were advanced to PAA in connection with the unauthorized trading losses through the issuance of $114.0 million of subordinated debt, which was repaid to us in May 2000 (see Note 3). In 2000, we paid cash dividends of $4.0 million on the Series F Preferred Stock.
Note 9 -- Capital Stock
Common and Preferred Stock
We have authorized capital stock consisting of 50.0 million shares of common stock, $0.10 par value, and 2 million shares of preferred stock, $1.00 par value. At December 31, 2000 and 1999, there were 17.5 million shares and 17.9 million shares of common stock outstanding, respectively, and 266,171 shares of preferred stock outstanding.
Stock Warrants and Options
At December 31, 2000, we had warrants outstanding which entitle the holders thereof to purchase an aggregate 150,000 shares of common stock at $25.00 per share expiring in 2002. Also outstanding at December 31, 1999 were warrants which entitled the holders to purchase an aggregate of 101,350 shares of common stock at $7.50 per share. These warrants were exercised in 2000. We have various stock option plans for our employees and directors (see Note 15).
Series D Cumulative Convertible Preferred Stock
In November 1997, we issued 46,600 shares of Series D Cumulative Convertible Preferred Stock (the "Series D Preferred Stock"). The Series D Preferred Stock has an aggregate stated value of $23.3 million and is redeemable at our option at 140% of stated value. If not previously redeemed or converted, the Series D Preferred Stock will automatically convert into 932,000 shares of common stock in 2012. Each share of the Series D Preferred Stock has a stated value of $500 and is convertible into common stock at a ratio of $25.00 of stated value for each share of Common Stock to be issued. The Series D Preferred Stock was initially recorded at $20.5 million, a discount of $2.8 million from the stated value of $23.3 million. Commencing January 1, 2000, the Series D Preferred Stock bears an annual dividend of $30.00 per share. Prior to this date, no dividends were accrued and the discount was amortized to retained earnings through December 31, 1999.
During 2000, we paid cash dividends of approximately $1.0 million on the Series D Preferred Stock. On January 2, 2001, we paid the fourth quarter 2000 cash dividend in the amount of $350,000 on the Series D Preferred Stock.
Series H Convertible Preferred Stock
Pursuant to the exchange offer discussed above (see Note 8), 169,571 shares of Series G Preferred Stock had been exchanged for our new Series H Preferred Stock as of December 28, 2000. The new Series H Preferred Stock is convertible into the same number of shares of common stock as the Series G Preferred Stock (33.33 shares of common), but does not bear a dividend and does not contain a mandatory redemption feature. In addition, if not earlier converted or exchanged, the Series H Preferred Stock will automatically convert into common stock on September 30, 2001.
Treasury Stock
In 2000, our Board of Directors authorized the repurchase of up to two million shares of our common stock. As of December 31, 2000, we had repurchased 1.3 million common shares at a cost of $23.6 million.
NOTE 10 -- EARNINGS PER SHARE
The following is a reconciliation of the numerators and the denominators of the basic and diluted earnings per share computations for income (loss) from continuing operations before extraordinary items and the cumulative effect of accounting change for the years ended December 31, 2000, 1999 and 1998 (in thousands, except per share amounts):
In 1999 and 1998, we recorded net losses and our options and warrants were not included in the computations of diluted earnings per share because their assumed conversion was antidilutive. In addition, our preferred stock is convertible into common stock but was not included in the computation of diluted earnings per share in 1999 and 1998 because the effect was antidilutive. See Notes 9 and 15 for additional information concerning outstanding options and warrants.
NOTE 11 -- INCOME TAXES
Our deferred income tax assets and liabilities at December 31, 2000 and 1999 consist of the tax effect of income tax carryforwards and differences related to the timing of recognition of certain types of costs incurred in both our upstream and midstream activities as follows (in thousands):
At December 31, 2000, we have a net deferred federal tax asset of $52.2 million, primarily attributable to net operating loss ("NOL") carryforwards. The minimum amount of future taxable income necessary to utilize the NOL carryforwards is $183.9 million. Based on current levels of pre-tax income, excluding nonrecurring items, management believes that it is more likely than not that we will generate taxable income from operations sufficient to realize the deferred tax asset.
At December 31, 2000, we have carryforwards of approximately $183.9 million of regular tax NOLs, $7.0 million of statutory depletion, $2.3 million of alternative minimum tax credits and $2.4 million of enhanced oil recovery credits. At December 31, 2000, we had approximately $165.0 million of alternative minimum tax NOL carryforwards available as a deduction against future alternative minimum tax income. The NOL carryforwards expire from 2008 through 2019.
Set forth below is a reconciliation between the income tax provision (benefit) computed at the United States statutory rate on income (loss) before income taxes and the income tax provision per the accompanying consolidated statements of operations (in thousands):
In accordance with certain provisions of the Tax Reform Act of 1986, a change of greater than 50% of our beneficial ownership within a three-year period (an "Ownership Change") will place an annual limitation on our ability to utilize our existing tax carryforwards. Under the Final Treasury Regulations issued by the Internal Revenue Service, we do not believe that an Ownership Change has occurred as of December 31, 2000.
NOTE 12 -- EARLY EXTINGUISHMENT OF DEBT
During 2000, we recognized extraordinary losses, consisting primarily of unamortized debt issue costs, totaling $5.0 million (net of minority interest of $7.0 million and deferred tax of $3.2 million) related to the permanent reduction of the All American Pipeline, L.P. term loan facility and the refinancing of PAA's credit facilities. In addition, interest and other income for the year ended December 31, 2000 includes $4.4 million of previously deferred net gains from terminated interest rate swaps as a result of the debt extinguishment (see Note 7). The extraordinary loss in 1999 of $0.5 million (net of minority interest of $0.7 million and deferred tax of $0.3 million) relates to the write-off of certain debt issue costs and penalties associated with the prepayment of debt.
NOTE 13 -- RELATED PARTY TRANSACTIONS
Reimbursement of Expenses of the General Partner and Its Affiliates
As the general partner for PAA, we have sole responsibility for conducting its business and managing its operations and we own all of the incentive distribution rights. Some of our senior executives who currently operate our business also manage the business of PAA. We do not receive any management fee or other compensation in connection with the management of PAA's business, but we are reimbursed for all direct and indirect expenses incurred on its behalf. For the years ended December 31, 2000 and 1999 and the period from November 23, 1998 to December 31, 1998, we were reimbursed approximately $63.8 million, $44.7 million and $0.5 million, respectively, for direct and indirect expenses on PAA's behalf. The reimbursed costs consist primarily of employee salaries and benefits. PAA does not employ any persons to manage its business. These functions are provided by the employees of the general partner and us.
Crude Oil Marketing Agreement
PAA is the exclusive marketer/purchaser for all of our equity crude oil production. The marketing agreement provides that PAA will purchase for resale at market prices all of our equity crude oil production for which PAA charges a fee of $0.20 per barrel. For the years ended December 31, 2000 and 1999 and the period from November 23, 1998 to December 31, 1998, we were paid approximately $244.9 million, $131.5 million and $4.1 million, respectively, for the purchase of crude oil under the agreement, including the royalty share of production. Prior to the marketing agreement, PAA's predecessor marketed our crude oil production and that of our subsidiaries and our royalty owners. We were paid approximately $83.4 million for the purchase of these products for the period from January 1, 1998 to November 22, 1998. In management's opinion, such purchases were made at prevailing market prices. PAA's predecessor did not recognize a profit on the sale of the crude oil purchased from us.
Financing
In December 1999, we loaned to PAA $114.0 million, which was repaid in May 2000 (see Note 3). Interest on the notes was $3.3 million and $0.6 million for the years ended December 31, 2000 and 1999, respectively.
To finance a portion of the purchase price of the Scurlock acquisition, we purchased 1.3 million Class B common units from PAA at $19.125 per unit, the market value of the common units on May 12, 1999 (see Note 6).
Long-Term Incentive Plans
We have adopted the Plains All American Inc. 1998 Long-Term Incentive Plan for employees and directors of the general partner and its affiliates. The Long-Term Incentive Plan consists of two components, a restricted unit plan and a unit option plan. The Long-Term Incentive Plan currently permits the grant of restricted units and unit options covering an aggregate of 975,000 common units. The plan is administered by the Compensation Committee of the general partner's board of directors.
Restricted Unit Plan. A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit. As of March 15, 2001, an aggregate of approximately 610,100 restricted units have been granted to employees. The general partner may, in the future, make additional grants under the plan. In general, restricted units
granted to employees during the subordination period will vest only upon, and in the same proportions as, the conversion of the subordinated units to common units. Grants made to non-employee directors of the general partner are eligible to vest prior to termination of the subordination period.
Unit Option Plan. The Unit Option Plan currently permits the grant of options covering common units. No grants have been made under the Unit Option Plan to date. However, the general partner may, in the future, make grants under the plan to employees and directors containing such terms as the committee shall determine, provided that unit options have an exercise price equal to the fair market value of the units on the date of grant. Unit options granted during the subordination period will become exercisable automatically upon, and in the same proportions as, the conversion of the subordinated units to common units, unless a later vesting date is provided.
Transaction Grant Agreements In addition to the grants made under the Restricted Unit Plan described above, the general partner, at no cost to PAA, agreed to transfer approximately 400,000 of its affiliates' common units (including distribution equivalent rights attributable to such units) to certain key officers and employees of the general partner and its affiliates. Generally, under these grants, the common units vest based on attaining a targeted operating surplus for a given year. Approximately 75,000 and 6,000 of the common units vest for 2001 and 2002, respectively, if the operating surplus generated in each year equals or exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and the related distribution on our general partner interest. If a tranche of common units does not vest for a particular year due to a common unit arrearage, such common units will vest at the time the common unit arrearages for such year have been paid. In addition, approximately 58,000 and 11,000 of the common units vest for 2001 and 2002, respectively, if the operating surplus generated in such year exceeds the amount necessary to pay the minimum quarterly distributions on all outstanding common units and subordinated units and the related distributions on the general partner interest. Approximately 69,000 and 113,000 (excluding approximately 20,000 units withheld for payment of federal income taxes) of the units vested for 1999 and 2000, respectively and approximately 47,000 common units remain unvested as no distribution on the subordinated units was made for the fourth quarter of 1999. Any common units remaining unvested shall vest upon, and in the same proportion as, the conversion of subordinated units to common units. Distribution equivalent rights are paid in cash at the time of the vesting of the associated common units. Notwithstanding the foregoing, all common units become vested if Plains All American Inc. is removed as general partner prior to January 1, 2002.
We recognized noncash compensation expense of approximately $2.7 million and $1.0 million for the years ended December 31, 2000 and 1999, respectively, related to the transaction grants which vested for 2000 and 1999. This amount is included in general and administrative expense on the Consolidated Statements of Operations. There were no transaction grants which vested for 1998.
NOTE 14 -- BENEFIT PLANS
Effective June 1, 1996, our board of directors adopted a nonqualified retirement plan (the "Plan") for certain of our officers. Benefits under the Plan are based on salary at the time of adoption, vest over a 15-year period and are payable over a 15-year period commencing at age 60. The Plan is unfunded.
Net pension expense for the years ended December 31, 2000, 1999 and 1998, is comprised of the following components (in thousands):
Summarized information of our retirement plan for the periods indicated is as follows (in thousands):
The weighted-average discount rate used in determining the projected benefit obligation was 7.5% and 7.8% for the years ended December 31, 2000 and 1999, respectively.
We also maintain a 401(k) defined contribution plan whereby we match 100% of an employee's contribution (subject to certain limitations in the plan), with matching contribution being made 50% in cash and 50% in common stock (the number of shares for the stock match being based on the market value of the common stock at the time the shares are granted). For the years ended December 31, 2000, 1999 and 1998, defined contribution plan expense was $1.4 million, $1.0 million and $0.5 million, respectively.
NOTE 15 -- STOCK COMPENSATION PLANS
Historically, we have used stock options as a long-term incentive for our employees, officers and directors under various stock option plans. The exercise price of options granted to employees is equal to or greater than the market price of the underlying stock on the date of grant. Accordingly, consistent with the provisions of APB 25, no compensation expense has been recognized in the accompanying financial statements.
We have options outstanding under our 1996, 1992 and 1991 plans, under which a maximum of 3.5 million shares of common stock were reserved for issuance. Generally, terms of the options provide for an exercise price of not less than the market price of our stock on the date of the grant, a pro rata vesting period of two to four years and an exercise period of five to ten years.
We have outstanding performance options to purchase a total of 500,000 shares of common stock which were granted to two executive officers. Terms of the options provide for an exercise price of $13.50, the market price on the date of grant, and an exercise period ending in August 2001. The performance options vest when the price of our common stock trades at or above $24.00 per share for any 20 trading days in any 30 consecutive trading day period or upon a change in control if certain conditions are met.
A summary of the status of our stock options as of December 31, 2000, 1999, and 1998, and changes during the years ending on those dates are presented below:
In October 1995, the Financial Accounting Standards Board issued SFAS 123 which established financial accounting and reporting standards for stock-based employee compensation. The pronouncement defines a fair value based method of accounting for an employee stock option or similar equity instrument. SFAS 123 also allows an entity to continue to measure compensation cost for those instruments using the intrinsic value-based method of accounting prescribed by APB 25. We have elected to follow APB 25 and related interpretations in accounting for our employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123 requires the use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, because the exercise price of our employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense has been recognized in the accompanying financial statements. We will recognize compensation expense under APB 25 in the future for the performance options described above, if certain conditions are met and the options vest.
Pro forma information regarding net income (loss) and earnings per share is required by SFAS 123 and has been determined as if we had accounted for our employee stock options under the fair value method as provided therein. The fair value for the options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for grants in 2000, 1999 and 1998: risk-free interest rates of 6.3% for 2000, 5.1% for 1999 and 5.6% for 1998; a volatility factor of the expected market price of our common stock of .50 for 2000, .50 for 1999 and .38 for 1998; no expected dividends; and weighted-average expected option lives of 2.6 years in 2000, 2.7 years in 1999 and 2.7 years in 1998.
The Black-Scholes option valuation model and other existing models were developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of and are highly sensitive to subjective assumptions including the expected stock price volatility. Because our employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not provide a reliable single measure of the fair value of its employee stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The pro forma information is not meant to be representative of the effects on reported net income (loss) for future years, because as provided by SFAS 123, the effects of awards granted before December 31, 1994, are not considered in the pro forma calculations.
Set forth below is a summary of our net income (loss) before extraordinary item and earnings per share as reported and pro forma as if the fair value based method of accounting defined in SFAS 123 had been applied (in thousands, except per share data).
The following table summarizes information about stock options outstanding at December 31, 2000 (share amounts in thousands):
NOTE 16 -- COMMITMENTS, CONTINGENCIES AND INDUSTRY CONCENTRATION
Commitments and Contingencies
We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be canceled at any time should they not be required for operations. Future non-cancelable commitments related to these items at December 31, 2000, are summarized below (in thousands):
2001 $7,021 2002 4,267 2003 4,289 2004 4,318 2005 4,337 Thereafter 2,940
Total expenses related to these commitments for the years ended December 31, 2000, 1999 and 1998 were $7.3 million, $9.3 million and $1.6 million, respectively.
In connection with its crude oil marketing, PAA provides certain purchasers and transporters with irrevocable standby letters of credit to secure their obligation for the purchase of crude oil. Generally, these letters of credit are issued for up to seventy day periods and are terminated upon completion of each transaction. At December 31, 2000, PAA had outstanding letters of credit of approximately $59.7 million. Such letters of credit are secured by PAA's crude oil inventory and accounts receivable. (see Note 7).
Under the amended terms of an asset purchase agreement between us and Chevron, commencing with the year beginning January 1, 2000, and each year thereafter, we are required to plug and abandon 20% of the then remaining inactive wells, which currently aggregate approximately 172. To the extent we elect not to plug and abandon the number of required wells,
we are required to escrow an amount equal to the greater of $25,000 per well or the actual average plugging cost per well in order to provide for the future plugging and abandonment of such wells. In addition, we are required to expend a minimum of $600,000 per year in each of the ten years beginning January 1, 1996, and $300,000 per year in each of the succeeding five years to remediate oil contaminated soil from existing well sites, provided there are remaining sites to be remediated. In the event we do not expend the required amounts during a calendar year, we are required to contribute an amount equal to 125% of the actual shortfall to an escrow account. We may withdraw amounts from the escrow account to the extent we expend excess amounts in a future year. Through December 31, 2000, we have not been required to make contributions to an escrow account.
Although we obtained environmental studies on our properties in California, the Sunniland Trend and the Illinois Basin and we believe that such properties have been operated in accordance with standard oil field practices, certain of the fields have been in operation for more than 90 years, and current or future local, state and federal environmental laws and regulations may require substantial expenditures to comply with such rules and regulations. In connection with the purchase of certain of our California properties, we received a limited indemnity from Chevron for certain conditions if they violate applicable local, state and federal environmental laws and regulations in effect on the date of such agreement. We believe that we do not have any material obligations for operations conducted prior to our acquisition of the properties from Chevron, other than our obligation to plug existing wells and those normally associated with customary oil field operations of similarly situated properties, there can be no assurance that current or future local, state or federal rules and regulations will not require us to spend material amounts to comply with such rules and regulations or that any portion of such amounts will be recoverable under the Chevron indemnity.
Consistent with normal industry practices, substantially all of our crude oil and natural gas leases require that, upon termination of economic production, the working interest owners plug and abandon non-producing wellbores, remove tanks, production equipment and flow lines and restore the wellsite. We have estimated that the costs to perform these tasks is approximately $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 2000, 1999 and 1998 include $0.5 million, $0.5 million and $0.8 million, respectively, of expense associated with these estimated future costs. For valuation and realization purposes of the affected crude oil and natural gas properties, these estimated future costs are also deducted from estimated future gross revenues to arrive at the estimated future net revenues and the Standardized Measure disclosed in Note 20.
As is common within the industry, we have entered into various commitments and operating agreements related to the exploration and development of and production from proved crude oil and natural gas properties and the marketing, transportation, terminalling and storage of crude oil. It is management's belief that such commitments will be met without a material adverse effect on our financial position, results of operations or cash flows.
Industry Concentration
Financial instruments which potentially subject us to concentrations of credit risk consist principally of trade receivables. Our accounts receivable are primarily from purchasers of crude oil and natural gas products and shippers of crude oil. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic, industry or other conditions. We generally require letters of credit for receivables from customers which are not considered investment grade, unless the credit risk can otherwise be reduced. The loss of an individual customer would not have a material adverse effect.
There are a limited number of alternative methods of transportation for our production. Substantially all of our California crude oil and natural gas production and our Sunniland Trend crude oil production is transported by pipelines, trucks and barges owned by third parties. The inability or unwillingness of these parties to provide transportation services to us for a reasonable fee could result in our having to find transportation alternatives, increased transportation costs or involuntary curtailment of a significant portion of our crude oil and natural gas production which could have a negative impact on future results of operations or cash flows.
NOTE 17 -- LITIGATION
Texas Securities Litigation. On November 29, 1999, a class action lawsuit was filed in the United States District Court for the Southern District of Texas entitled Di Giacomo v. Plains All American Pipeline, et al. The suit alleged that Plains All American Pipeline, L.P. and certain of the general partner's officers and directors violated federal securities laws, primarily in connection with unauthorized trading by a former employee. An additional nineteen cases have been filed in the Southern District of Texas, some of which name the general partner and us as additional defendants. All of the federal securities claims are being consolidated into two actions. The first consolidated action is that filed by purchasers of our common stock and options, and is captioned Koplovitz v. Plains Resources Inc., et al. The second consolidated action is that filed by purchasers of PAA's common units, and is captioned Di Giacomo v. Plains All American Pipeline, L.P., et al. Plaintiffs alleged that the defendants were liable for securities fraud violations under Rule 10b-5 and Section 20(a) of the Securities Exchange Act of 1934 and for making false registration statements under Sections 11 and 15 of the Securities Act of 1933.
We and PAA reached an agreement with representatives for the plaintiffs for the settlement of all of the class actions, and in January 2001, PAA deposited approximately $30.0 million under the terms of the settlement agreement. The total cost of the settlement to us and PAA, including interest and expenses and after insurance reimbursements, was $14.9 million. Of that amount, $1.0 million was allocated to us by agreement between special independent committees of our board of directors and the board of directors of Plains All American Inc. All such amounts were reflected in our financial statements at December 31, 2000. The settlement is subject to a number of conditions, including final approval by the court. A hearing is set for March 30, 2001. The settlement agreement does not affect the Texas Derivative Litigation and Delaware Derivative Litigation described below.
Delaware Derivative Litigation. On December 3, 1999, two derivative lawsuits were filed in the Delaware Chancery Court, New Castle County, entitled Susser v. Plains All American Inc., et al and Senderowitz v. Plains All American Inc., et al. These suits, and three others which were filed in Delaware subsequently, named the general partner, its directors and certain of its officers as defendants, and allege that the defendants breached the fiduciary duties that they owed to PAA and its unitholders by failing to monitor properly the activities of its employees. The court has consolidated all of the cases under the caption In Re Plains All American Inc. Shareholders Litigation, and has designated the complaint filed in Sussex v. Plains All American Inc. as the operative complaint in the consolidated action. A motion to dismiss was filed on behalf of the defendants on August 11, 2000.
The plaintiffs in the Delaware derivative litigation seek that the defendants
. account for all losses and damages allegedly sustained by Plains All American from the unauthorized trading losses;
. establish and maintain effective internal controls ensuring that our affiliates and persons responsible for our affairs do not engage in wrongful practices to Plains All American;
. pay for the plaintiffs' costs and expenses in the litigation, including reasonable attorneys' fees, accountants' fees and experts' fees; and
. provide the plaintiffs any additional relief as may be just and proper under the circumstances.
We have reached an agreement in principle with the plaintiffs, subject to approval by the Delaware court, to settle the Delaware litigation for approximately $1.1 million.
Texas Derivative Litigation. On July 11, 2000, a derivative lawsuit was filed in the United States District Court for the Southern District of Texas entitled Fernandez v. Plains All American Inc., et al., naming the general partner, its directors and certain of its officers as defendants. This lawsuit contains the same claims and seeks the same relief as the Delaware derivative litigation described above. A motion to dismiss was filed on behalf of the defendants on August 14, 2000.
We intend to vigorously defend the claims made in Texas derivative litigation. We believe that Delaware court approval of the settlement of the Delaware derivative litigation will effectively preclude prosecution of the Texas derivative litigation. However, there can be no assurance that we will be successful in our defense or that this lawsuit will not have a material adverse effect on our financial position or results of operation.
We, in the ordinary course of business, are a claimant and/or defendant in various other legal proceedings. Management does not believe that the outcome of these legal proceedings, individually and in the aggregate, will have a materially adverse effect on our financial condition, results of operations or cash flows.
NOTE 18 -- FINANCIAL INSTRUMENTS
Derivatives
We utilize derivative financial instruments, as defined in Statement of Financial Accounting Standards No. 119, "Disclosure About Derivative Financial Instruments and Fair Value of Financial Instruments" to hedge our exposure to price volatility on crude oil and do not use such instruments for speculative trading purposes. These arrangements expose us to credit risk (as to counterparties) and to risk of adverse price movements in certain cases where our purchases are less than expected. In the event of non-performance of a counterparty, we might be forced to acquire alternative hedging arrangements or be required to honor the underlying commitment at then-current market prices. In order to minimize credit risk relating to the non-performance of a counterparty, we enter into such contracts with counterparties that are considered investment grade, periodically review the financial condition of such counterparties and continually monitor the effectiveness of derivative financial instruments in achieving our objectives. In view of our criteria for selecting counterparties, our process for monitoring the financial strength of these counterparties and our experience to date in successfully completing these transactions, we believe that the risk of incurring significant financial statement loss due to the non- performance of counterparties to these transactions is minimal.
We have entered into various arrangements, using a combination of swaps, collars and purchased puts and calls, to fix the NYMEX crude oil spot price for a significant portion of our crude oil production. On December 31, 2000, these arrangements provided for a NYMEX crude oil price of approximately $23.00 per barrel on 21,500 barrels per day from January 1, 2001, through December 31, 2001, with full market price participation up to an average of $27.00 per barrel. For 2002, we have entered into various arrangements that provide for us to receive an average minimum NYMEX WTI price of $23.00 per barrel on 10,000 barrels per day with full market price participation up to an average of $24.90 per barrel. Location and quality differentials attributable to our properties and the cost of the hedges are not included in the foregoing prices. Because of the quality and location of our crude oil production, these adjustments will reduce our net price per barrel. The agreements provide for monthly settlement based on the differential between the agreement price and the actual NYMEX price. Gains or losses are recognized in the month of related production and are included in crude oil and natural gas sales. Such contracts resulted in a reduction of revenues of $79.4 million and $11.1 million for the years ended December 31, 2000 and 1999, respectively. At December 31, 2000, we had an unrealized gain of $17.3 million with respect to such contracts and at December 31, 1999, we had an unrealized loss of $22.0 million.
At December 31, 2000, our hedging activities included crude oil futures contracts maturing in 2001 through 2002, covering approximately 3.2 million barrels of crude oil. Since such contracts are designated as hedges and correlate to price movements of crude oil, any gains or losses resulting from market changes will be largely offset by losses or gains on our hedged inventory or anticipated purchases of crude oil. Such contracts resulted in a reduction in revenues of $15.1 million and $17.8 million for the years ended December 31, 2000 and 1999, respectively. The unrealized loss at December 31, 2000 and December 31, 1999 was $7.8 million and $9.8 million, respectively.
Interest rate swaps and collars are used to hedge underlying debt obligations. These instruments hedge specific debt issuances and qualify for hedge accounting. The interest rate differential is reflected as an adjustment to interest expense over the life of the instruments. At December 31, 2000, we had interest rate swap and collar arrangements for an aggregate notional principal amount of $240.0 million. The adjustment to interest expense resulting from interest rate swaps for the years ended December 31, 2000 and 1999 was a $0.3 million gain and a $0.2 million loss, respectively. These instruments are based on LIBOR margins and provide for (1) a floor of 5% and a ceiling of 6.5% with an expiration date of February 2001 for $90.0 million notional principal amount (2) a floor of 6% and a ceiling of 8% with an expiration date of August 2002 for $125.0 million notional principal amount and (3) a ceiling of 5.7% with an expiration date of July 2008 for $25.0 million notional principal amount. The counterparty has the option to terminate the $25.0 million swap in July 2003, and either party may terminate in July 2005.
Fair Value of Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of Statement of Financial Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments ("SFAS 107"). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.
The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. Crude oil futures contracts permit settlement by delivery of the crude oil and, therefore, are not financial instruments, as defined. The carrying amounts and fair values of our other financial instruments are as follows (in thousands):
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. The fair value of the redeemable preferred stock was provided by an outside source at December 31, 2000 and was estimated to be its liquidation value at December 31, 1999. The fair value of the crude oil swap and collar arrangements are estimated based on quoted prices from independent reporting services compared to the contract price of the swap or collar. The fair value of the interest rate swap and collar agreements is based on current termination values or quoted market prices of comparable contracts at December 31, 2000 and 1999.
NOTE 19 -- SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Selected cash payments and noncash activities were as follows (in thousands):
NOTE 20 -- CRUDE OIL AND NATURAL GAS ACTIVITIES
Costs Incurred
Our oil and natural gas acquisition, exploration, exploitation and development activities are conducted in the United States. The following table summarizes the costs incurred during the last three years (in thousands).
YEAR ENDED DECEMBER 31, --------------------------------- 2000 1999 1998 -------- -------- --------- Property acquisitions costs: Unproved properties $ 73 $ 879 $ 6,266 Proved properties 2,433 2,880 3,851 Exploration costs 872 4,101 1,657 Exploitation and development costs 77,550 65,119 89,161 -------- -------- --------- $ 80,928 $ 72,979 $ 100,935 ======== ======== =========
Capitalized Costs
Under full cost accounting rules as prescribed by the SEC, unamortized costs of proved crude oil and natural gas properties are subject to a ceiling, which limits such costs to the Standardized Measure (as described below). At December 31, 1998, the capitalized costs of our proved crude oil and natural gas properties exceeded the Standardized Measure and we recorded a noncash, after tax charge to expense of $109.0 million ($173.9 million pre-tax). The following table presents the aggregate capitalized costs subject to amortization relating to our crude oil and natural gas acquisition, exploration, exploitation and development activities, and the aggregate related accumulated DD&A (in thousands).
DECEMBER 31, ---------------------- 2000 1999 --------- --------- Proved properties $ 762,245 $ 671,928 Accumulated DD&A (408,337) (387,437) --------- --------- $ 353,908 $ 284,491 ========= =========
The DD&A rate per equivalent unit of production excluding the writedown in 1998 was $2.31, $2.13 and $3.00 for the years ended December 31, 2000, 1999 and 1998, 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 (in thousands).
DECEMBER 31, ----------------------------------- 2000 1999 1999 --------- --------- ---------
Acquisition costs $34,087 $42,261 $47,657 Exploration costs 4,456 4,842 2,467 Capitalized interest 4,038 4,928 4,421 --------- --------- --------- $42,581 $52,031 $54,545
Unproved property costs not subject to amortization consist mainly of acquisition and lease costs and seismic data related to unproved areas. We will continue to evaluate these properties over the lease terms; however, the timing of the ultimate evaluation and disposition of a significant portion of the properties has not been determined. Costs associated with seismic data and all other costs will become subject to amortization as the prospects to which they relate are evaluated. Approximately 11%, 16% and 19% of the balance in unproved properties at December 31, 2000, related to additions made in 2000, 1999 and 1998, respectively.
During 2000, 1999 and 1998, we capitalized $4.4 million, $4.4 million and $3.7 million, respectively, of interest related to the costs of unproved properties in the process of development.
Supplemental Reserve Information (Unaudited)
The following information summarizes our net proved reserves of crude oil (including condensate and natural gas liquids) and natural gas and the present values thereof for the three years ended December 31, 2000. The following reserve information is based upon reports of the independent petroleum consulting firms of H.J. Gruy and Company, Netherland Sewell & Associates, Inc., and Ryder Scott Company in 2000, 1999 and 1998. The estimates are in accordance with regulations prescribed by the SEC.
In management's opinion, the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are believed to be reasonable. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of crude oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree speculative, the quantities of crude oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and
future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the Standardized Measure shown below represents estimates only and should not be construed as the current market value of the estimated crude oil and natural gas reserves attributable to our properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year's estimates. Such revisions reflect additional information from subsequent exploitation and development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.
Decreases in the prices of crude oil and natural gas have had, and could have in the future, an adverse effect on the carrying value of our proved reserves and our revenues, profitability and cash flow. Almost all of our reserve base (approximately 94% of year-end 2000 reserve volumes) is comprised of crude oil properties that are sensitive to crude oil price volatility.
Estimated Quantities of Crude Oil and Natural Gas Reserves (Unaudited)
The following table sets forth certain data pertaining to our proved and proved developed reserves for the three years ended December 31, 2000 (in thousands).
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The Standardized Measure of discounted future net cash flows relating to proved crude oil and natural gas reserves is presented below (in thousands):
DECEMBER 31, --------------------------------------- 2000 1999 1998 ----------- ----------- ----------
Future cash inflows $ 6,057,344 $ 4,837,010 $1,102,863 Future development costs (275,862) (231,914) (117,924) Future production expense (2,875,301) (1,758,572) (546,091) Future income tax expense (887,107) (845,133) - ----------- ----------- ---------- Future net cash flows 2,019,074 2,001,391 438,848 Discounted at 10% per year (1,099,413) (1,073,591) (211,905) ----------- ----------- ---------- Standardized measure of discounted future net cash flows $ 919,661 $ 927,800 $ 226,943 =========== =========== ==========
The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:
1. An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions. 2. In accordance with SEC guidelines, the engineers' estimates of future net revenues from our proved properties and the present value thereof are made using crude oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate
treatment, including the use of fixed and determinable contractual price escalations. We have entered into various fixed price and floating price collar arrangements to fix or limit the NYMEX crude oil price for a significant portion of our crude oil production. Arrangements in effect at December 31, 2000 are discussed in Note 18. Such arrangements are not reflected in the reserve reports. The overall average year-end prices used in the reserve reports as of December 31, 2000, were $21.02 per barrel of crude oil, condensate and natural gas liquids and $14.63 per Mcf of natural gas. 3. The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs.
4. The reports reflect the pre-tax Present Value of Proved Reserves to be $1.3 billion, $1.2 billion and $226.9 million at December 31, 2000, 1999 and 1998, respectively. SFAS No. 69 requires us to further reduce these estimates by an amount equal to the present value of estimated income taxes which might be payable by us in future years to arrive at the Standardized Measure. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.
The principal sources of changes in the Standardized Measure of the future net cash flows for the three years ended December 31, 2000, are as follows (in thousands):
Results of Operations for Oil and Gas Producing Activities
The results of operations from oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. Income tax (expense) or benefit was determined by applying the statutory rates to pretax operating results (in thousands).
NOTE 21 - SUBSEQUENT EVENTS
Acquisitions
Murphy Oil Company Ltd. Midstream Operations
On March 1, 2001, PAA signed an agreement to purchase substantially all of the crude oil pipeline, gathering, storage and terminalling assets of Murphy Oil Company Ltd. ("Murphy") for approximately $155.0 million in cash, plus an additional
cash payment, to be determined prior to closing in accordance with the agreement, for excess inventory in the systems (estimated to be approximately $5.0 million). The principal assets to be acquired include approximately 450 miles of crude oil and condensate transmission mainlines and associated gathering and lateral lines, and approximately 1.1 million barrels of crude oil storage and terminalling capacity located primarily in Kerrobert, Saskatchewan, approximately 200,000 barrels of linefill, as well as a currently inactive 108- mile mainline system and 121 trailers used primarily for crude oil transportation.
Murphy has agreed to continue to transport production from fields currently delivering crude oil to these pipeline systems, under a new long-term contract. The current volume is approximately 11,000 barrels per day. The pipeline systems transport approximately 200,000 barrels per day of light, medium and heavy crudes, as well as condensate.
Canadian Marketing Assets
PAA has entered into a letter of intent to purchase the assets of a Canadian marketing company. The expected purchase price is approximately $43.0 million, of which approximately $18.0 million will be subject to certain performance targets. The marketing company currently gathers approximately 75,000 barrels per day of crude oil and markets approximately 26,000 barrels per day of natural gas liquids. Tangible assets include a crude oil handling facility, a 100,000 barrel tank facility and working capital of approximately $8.5 million.
Initial financing for the acquisitions will be provided via an expansion of PAA's existing revolving credit, letter of credit and inventory facility. The expanded facility will initially be underwritten by Fleet Boston and will consist of a $100.0 million five-year term loan and a $30.0 million revolving credit facility that will expire in April 2005.
NOTE 22--QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table shows summary financial data for 2000 and 1999 (in thousands, except per share data):
- ------------------ (1) For 2000, includes a $5.0 million charge to reserve for potentially uncollectible accounts receivable. (2) 2000 has been restated to reflect the adoption of SAB 101. The effect of this change in accounting for crude oil inventories on prior periods is deminimus. (3) These amounts represent the reclassification from previously reported amounts due to the adoption of EITF 99-19 and are included in revenues above (see Note 2). (4) Includes the effects of the unauthorized trading losses for the third and fourth quarters of 2000 and all quarters of 1999 (see Note 3). (5) Excludes a net gain of $9.8 million related to PAA's unit offerings in 1999.
NOTE 23 -- OPERATING SEGMENTS
Our operations consist of two operating segments: (1) Upstream Operations - engages in the acquisition, exploitation, development, exploration and production of crude oil and natural gas and (2) Midstream Operations - engages in pipeline transportation, purchases and resales of crude oil at various points along the distribution chain and the leasing of certain terminalling and storage assets. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 1). We evaluate segment performance based on gross margin, gross profit and income before income taxes and extraordinary items.
(a) Revenues for the marketing, gathering, terminalling and storage segment include the effects of the adoption of EITF 99-19 (see Note 2). For the years ending December 31, 2000 and 1999 and 1998, revenues have been reclassified by $2.5 billion, $6.2 billion $2.3 billion, respectively. (b) Intersegment revenues and transfers were conducted on an arm's-length basis. (c) Gross margin is calculated as operating revenues less operating expenses. (d) Gross profit is calculated as operating revenues less operating expenses and general and administrative expenses. (e) Differences between segment totals and company totals represent the net gain of $60.8 million recorded upon the formation of PAA, which was not allocated to segments.
The following table reconciles segment revenues to amounts reported in our financial statements:
Customers accounting for more than 10% of consolidated sales for the periods indicated are as follows:
- -------------- (1) These customers pertain to our midstream segment. Represents percentage of oil and gas sales revenues plus marketing, transportation, storage and terminalling revenues. (2) PAA is the exclusive marketer/purchaser for all our equity crude oil production. These percentages represent the entities that purchased our equity crude production from PAA. We believe that the loss of an individual customer would not have a material adverse effect on our results of operations.
NOTE 24 -- CONSOLIDATING FINANCIAL STATEMENTS
The following financial information presents consolidating financial statements which include:
. the parent company only ("Parent"); . the guarantor subsidiaries on a combined basis ("Guarantor Subsidiaries"); . the nonguarantor subsidiaries on a combined basis ("Nonguarantor Subsidiaries"); . elimination entries necessary to consolidate the Parent, the Guarantor Subsidiaries and the Nonguarantor Subsidiaries; and . Plains Resources Inc. on a consolidated basis.
These statements are presented because the Series A-E Notes discussed in Note 7 are not guaranteed by PAA and our consolidated financial statements include the accounts of PAA.
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS) DECEMBER 31, 2000
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEET (IN THOUSANDS) DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 2000
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONSOLIDATING STATEMENT OF OPERATIONS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 1998
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 2000
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 1999
PLAINS RESOURCES INC. AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS (IN THOUSANDS) YEAR ENDED DECEMBER 31, 1998