SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 7, 2003
PLAINS EXPLORATION & PRODUCTION COMPANY
(Exact name of registrant as specified in charter)
| Delaware | 33-0430755 | |
| (State of Incorporation) | (I.R.S. Employer Identification No.) | |
001-31470
(Commission File No.)
500 Dallas Street, Suite 700
Houston, Texas 77002
(Address of Principal Executive Offices)
(Zip Code)
Registrant’s telephone number, including area code: (713) 739-6700
Item 7. Financial Statements and Exhibits
(c) Exhibit 99.1—Press Release dated August 7, 2003
Item 9 and 12. Regulation FD Disclosure; Results of Operations and Financial Condition
Plains Exploration & Production Company (the “Company”, “our”, “we” or “us”) today issued a press release reporting its second quarter results. The Company is furnishing the press release, attached as Exhibit 99.1, pursuant to Item 9 and Item 12 of Form 8-K. The Company is also furnishing pursuant to Item 9 its estimates of certain operating and financial results for the three months ended September 30, 2003 and three months ended December 31, 2003. In accordance with General Instruction B.2. of Form 8-K, the information presented under this Item 9, including Exhibit 99.1, shall not be deemed “filed” for purposes of Section 18 of the Securities Act of 1934, as amended, nor shall it be deemed incorporated by reference in any filing under the Securities Act of 1933, as amended, except as expressly set forth by specific reference in such a filing.
Forward-Looking Statements and Associated Risks
All statements, other than statements of historical fact, included in this report are forward-looking statements, including, but not limited to, statements identified by the words “anticipate,” “believe,” “estimate,” “expect,” “plan,” “intend” and “forecast” and similar expressions and statements regarding our business strategy, plans and objectives of our management for future operations. These statements reflect our current views with respect to future events, based on what we believe are reasonable assumptions. These statements, however, are subject to certain risks, uncertainties and assumptions, including, but not limited to:
| · | uncertainties inherent in the exploration for and development and production of oil and gas and in estimating reserves; |
| · | the consequences of any potential change in the relationship between us and Plains Resources; |
| · | unexpected difficulties in integrating our and 3TEC’s operations as a result of our recent acquisition; |
| · | the consequences of our officers and employees providing services to both us and Plains Resources and not being required to spend any specific percentage or amount of time on our business; |
| · | unexpected future capital expenditures (including the amount and nature thereof); |
| · | impact of oil and gas price fluctuations; |
| · | the effects of our indebtedness, which could adversely restrict our ability to operate, could make us vulnerable to general adverse economic and industry conditions, could place us at a competitive disadvantage compared to our competitors that have less debt, and could have other adverse consequences; |
| · | the effects of competition; |
| · | the success of our risk management activities; |
| · | the availability (or lack thereof) of acquisition or combination opportunities; |
| · | the impact of current and future laws and governmental regulations; |
| · | environmental liabilities that are not covered by an indemnity or insurance; and |
| · | general economic, market or business conditions. |
If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, actual results may vary materially from those in the forward-looking statements. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
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Disclosure of 2003 Estimates
The following table and accompanying notes reflect current estimates of certain results for 2003 for Plains Exploration & Production Company. These estimates are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management’s assumptions and the Company’s future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and estimates can or will be met. Any number of factors could cause actual results to differ materially from those in the following table, including but not limited to the factors discussed above. The estimates set forth below are given as of the date hereof only based on information available as of the date hereof. The Company undertakes no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in the Company’s filings with the Securities and Exchange Commission (“SEC”), and we encourage you to review such filings.
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Operating and Financial Guidance
| Quarter Ended September 30, 2003 | Quarter Ended December 31, 2003 | |||
Estimated Production Volumes | ||||
Oil and Liquids—MBbls per day | 26.5–27.3 | 25.8–26.6 | ||
Gas—MMcf per day | 76.5–79.2 | 86.4–89.1 | ||
Barrels of oil equivalent—MBOE per day | 39.3–40.5 | 40.2–41.5 | ||
Estimated Oil Price differential to NYMEX (pre-hedge)—$/Bbl | $4.00–$4.35 | $4.00–$4.35 | ||
Oil Hedges—barrels per day | ||||
Swaps—Average price $24.10 per barrel | 20,250 | 20,250 | ||
Natural Gas Hedges—MMBtu per day | ||||
Swaps—$5.02/MMBtu | 50,000 | 50,000 | ||
Operating Costs per BOE | ||||
Production expenses | $6.65–$6.75 | $6.65–$6.75 | ||
Gathering and transportation | $0.20–$0.25 | $0.20–$0.25 | ||
Production and ad valorem taxes | $1.15–$1.20 | $1.15–$1.20 | ||
General and administrative | ||||
G&A excluding items below | $1.40–$1.50 | $1.40–$1.50 | ||
Noncash compensation expense | $0.05–$0.10 | $0.05–$0.10 | ||
Stock appreciation rights | See Note 7 | See Note 7 | ||
Merger related expenses | See Note 8 | See Note 8 | ||
DD&A—oil and gas | $4.00 | $4.00 | ||
Other expense ($ in thousands) | ||||
DD&A—other | 650 | 650 | ||
Accretion of asset retirement obligation | 750 | 750 | ||
Interest expense | See Note 11 | See Note 11 | ||
Book Tax Rate | ||||
Current | 9% | 9% | ||
Deferred | 32% | 32% | ||
Weighted Average Equivalent shares outstanding (in thousands) | ||||
Basic | 40,100 | 40,100 | ||
Diluted | 40,700 | 40,700 | ||
Capital Expenditures ($ in thousands) | $40,000–$45,000 | $18,000–$20,000 | ||
| 1. | Acquisition of 3TEC Energy Corporation. Estimates provided reflect the acquisition of 3TEC Energy Corporation which closed on June 4, 2003. |
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| 2. | Estimated production volumes. Production estimates are based on historical operating performance and trends and the Company’s 2003 capital budget and assume that market demand and prices for oil and gas will continue at levels that allow for profitable production of these products. Estimated volumes from exploitation/exploratory drilling are based on the Company’s risked assessment of the projects. The Company is evaluating several small, non-core assets that it may elect to sell to enable it to focus on its core properties, maintain financial flexibility, reduce overhead and redeploy the proceeds to activities that the Company believes have a higher potential financial return. Estimated production volumes have not been adjusted to reflect the sale of non-core properties. |
| 3. | Estimated oil price differentials. The Company’s realized wellhead oil price is lower than the NYMEX index level as a result of area and quality differentials. The Company has locked in a fixed price differential to NYMEX on approximately 65% of its oil production for the third and fourth quarter of 2003. |
| 4. | Oil and gas hedges. Oil and gas hedge positions reflect contracts in place as of the date of this report. Location and quality differentials attributable to our properties are not included in the hedge prices. |
| 5. | Production expenses. Production expenses include salaries and benefits of personnel involved in production activities, electric and fuel costs, maintenance costs, and other costs necessary to operate the Company’s producing properties. Actual expenses may vary from the estimates provided due to the level of repair and workover activity, increases in costs for materials and services, increases in costs for electricity and fuel and other factors. Per unit costs will increase if production is less than anticipated due to the fixed expense component of the Company’s production expenses that do not decrease if the production level declines. |
| 6. | Production and ad valorem taxes. Production and ad valorem taxes include ad valorem taxes that are assessed on an annual basis based on the property value determined by the taxing authority and production and severance taxes that vary depending on production levels and product prices. Production taxes included in the estimates provided were calculated assuming a gas price of $5.00 per Mcf for the third quarter and $5.31 per Mcf for the fourth quarter. |
| 7. | General and administrative. The G&A estimates provided exclude any expense related to stock appreciation rights which are subject to variable accounting. As a result, the Company’s results of operations will be affected by fluctuations in the price of its common stock. At the end of each quarter the Company will compare the per share closing price of its common stock to the exercise price of each outstanding or unexercised stock appreciation right that is vested or for accounting purposes is deemed vested at the end of the period. For example, if a SAR is scheduled to vest on December 31, for accounting purposes one-fourth of the shares are deemed to vest at the end of each quarter even though no vesting occurs until December 31. To the extent the closing price at the end of each period exceeds the exercise price, the Company will recognize the excess as compensation expense to the extent not previously recognized. If the quarter-end closing price decreases compared to prior periods, the Company will reduce compensation expense to the extent previously recognized. As of June 30, 2003 the Company has approximately 3.7 million SARs outstanding with an average exercise price of $8.85, of which 2.6 million of the SARs were deemed vested. The Company will incur cash expenditures as SARs are exercised, but its common shares outstanding will not increase. |
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| 8. | Merger related expenses. Certain costs related to the 3TEC acquisition and the integration of the two companies will be recognized as an expense during 2003. Such costs include certain compensation items related to the acquisition, accounting system integration, moving and relocation related to consolidation of office locations and certain severance and relocation costs. The Company expects that acquisition and integration expenses will total $5.0 million to $6.0 million in 2003. These costs are not included in the G&A estimates provided because the amounts are difficult to estimate and the Company does not consider these expenses as a recurring cost of ongoing operations. |
| 9. | DD&A—oil and gas. The oil and gas DD&A rate for January 1, 2003 through May 31, 2003 was approximately $3.20 per BOE based on the book value of the Company’s proved oil and gas properties at December 31, 2002 and the reserve volumes and future development costs included in the proved reserve reports at that date. The Company estimates that the DD&A rate for the remainder of the year will be approximately $4.00 per BOE including reserve volumes, costs incurred and future development costs related to the 3TEC acquisition. The fourth quarter DD&A rate will be adjusted based on year-end 2003 proved reserve volumes. |
| 10. | Accretion of asset retirement obligation. Effective January 1, 2003 the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). SFAS 143 requires entities to record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. When the liability is initially recorded, the entity should capitalize the retirement cost of the related long-lived asset. Each period the liability is accreted to its then present value, and the capitalized cost is depreciated over the useful life of the related asset. In prior periods the Company included estimated future costs of abandonment and dismantlement in its full cost amortization base and these costs were amortized as a component of depletion expense. |
| 11. | Interest expense. The Company’s interest expense will consist of interest on: |
| a. | $275 million of 8.75% Senior Subordinated Notes. Interest expense for the third quarter and fourth quarter for this debt will be $6.0 million per quarter, including amortization of related premium and discount. |
| b. | Amounts outstanding under the Company’s $500 million revolving credit facility (“Credit Facility”). The Credit Facility provides for grid pricing at LIBOR or Prime at the Company’s option plus a margin based on the percentage of the borrowing base then being utilized as follows: |
| <25% | 25% to 49% | 50% to 74% | 75% to 89% | >=90% | |||||||||||
LIBOR Loans | 1.375 | % | 1.500 | % | 1.625 | % | 1.750 | % | 2.000 | % | |||||
Prime Loans | 0.125 | % | 0.250 | % | 0.375 | % | 0.500 | % | 0.750 | % | |||||
Commitment Fee | 0.375 | % | 0.375 | % | 0.500 | % | 0.500 | % | 0.500 | % |
| c. | The Company has an interest rate swap agreement that expires on October 2004 under which it receives LIBOR and pays 3.9% on a notional amount of $7.5 million. |
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| d. | Interest expense will be reduced by capitalized interest. The Company estimates it will capitalize approximately $1.2 million per quarter of interest during each of the third and fourth quarter of 2003. |
| 12. | Book Tax Rate. The Company estimates that its total tax rate will be 41%, consisting of a deferred tax rate of 32% and a currently payable rate of 9%. The actual rate may vary from the estimates provided due to changes in estimated capital expenditures, production levels, product prices and other factors. The Company’s deferred and current tax rates are based on current estimates of taxable income. |
| 13. | Weighted average equivalent shares outstanding. Estimated basic shares outstanding are based on shares outstanding on July 31, 2003. Estimated diluted shares are based on basic shares outstanding, plus restricted shares. Because stock appreciation rights are payable in cash rather than stock, they are not a common stock equivalent and are not included in the earnings per share calculation. The Company does not have any outstanding stock options or warrants. |
| 14. | Write-downs under full cost ceiling test rules. Under the SEC’s full cost accounting rules, the Company reviews the carrying value of its proved oil and gas properties at the end of each quarter. Under these rules, capitalized costs of proved oil and gas properties (net of accumulated DD&A, and including deferred income taxes) may not exceed a “ceiling” equal to the present value (discounted at 10%) of estimated future cash flows from proved oil and gas reserves of such properties (including the effect of any hedging related activities) reduced by future operating expenses, development expenditures and abandonment costs (net of salvage values) and estimated future income taxes. The rules require that the Company price its future oil and gas production at the prices in effect at the end of each fiscal quarter and require a write-down if its capitalized costs exceed the “ceiling” even if prices decline for only a short period of time. The Company has had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that the Company’s estimate of discounted future net revenues from proved oil and gas reserves will change in the near term. If oil and gas prices decline significantly in the future, even if only for a short period of time, write-downs of the Company’s oil and gas properties could occur. Write-downs required by these rules do not directly impact the Company’s cash flows from operating activities. |
| 15. | Goodwill. The Company recorded approximately $144 million of goodwill in connection with the 3TEC acquisition. Goodwill represents the excess of the purchase price paid by the Company plus liabilities assumed, including deferred taxes recorded in connection with the acquisition, over the estimated fair market value of the tangible net assets acquired. Goodwill is not amortized, but instead must be tested at least annually for impairment by applying a fair-value based test. Goodwill is deemed impaired to the extent of any excess of its carrying amount over the residual fair-value of the reporting unit. Any impairment could significantly reduce earnings during the period in which the impairment occurs, and would result in a corresponding reduction to goodwill and stockholders’ equity. The most significant factors that could result in the impairment of our goodwill would be significant declines in oil and gas prices and/or reserve volumes which would result in a decline in the fair value of our oil and gas properties. |
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
PLAINS EXPLORATION & PRODUCTION COMPANY | ||
| Date: August 7, 2003 | /s/ Cynthia A. Feeback | |
Cynthia A. Feeback Senior Vice President—Accounting and Treasurer | ||
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