UNITED STATES
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): November 6, 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.)
700 Milam, Suite 3100
Houston, Texas 77002
(Address of Principal Executive Offices)
(Zip Code)
Registrant’s telephone number, including area code: (832) 239-6000
Plains Exploration & Production Company
Table of Contents
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Plains Exploration & Production Company
Item 7. Financial Statements and Exhibits
(c) Exhibit 99.1 – Press Release dated November 6, 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 third 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 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. |
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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.
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 and accompanying notes, 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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Plains Exploration & Production Company
Operating and Financial Guidance
| | | Three Months Ended
December 31, 2003
|
Estimated Production Volumes | | |
Oil and Liquids—MBbls per day | | 25.2 – 26.0 |
Gas—MMcf per day | | 79.8 – 81.0 |
Barrels of oil equivalent—MBOE per day | | 38.5 – 39.5 |
| |
Estimated Oil Price Differential to NYMEX (pre-hedge)—$/Bbl | | $4.00 – $4.25 |
| |
Oil Hedges—barrels per day | | |
Swaps—average price $24.10 per barrel | | 20,250 |
Natural Gas Hedges—MMBtu per day | | |
Swaps—$5.02/MMBtu | | 50,000 |
| |
Operating Costs per BOE | | |
Production expenses | | $6.75 – $7.00 |
Gathering and transportation | | $0.30 – $0.35 |
Production and ad valorem taxes | | $0.90 – $1.10 |
General and administrative | | |
G&A excluding items below | | $1.40 – $1.50 |
Noncash compensation expense | | $0.05 – $0.10 |
Stock appreciation rights | | See Note 6 |
Merger related expenses | | See Note 7 |
DD&A—oil and gas | | $4.00 |
Other expense ($ in thousands) | | |
DD&A—other | | $650 |
Accretion of asset retirement obligation | | $750 |
Interest expense | | See Note 10 |
| |
Book Tax Rate | | |
Current | | 9% |
Deferred | | 32% |
| |
Weighted Average Equivalent Shares Outstanding (in thousands) | | |
Basic | | 40,100 |
Diluted shares | | 40,800 |
| |
Capital Expenditures ($ in thousands) | | $36,000 – $39,000 |
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Notes:
| | 1. | Estimated production volumes. Production estimates are based on historical operating performance and trends and our 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/exploration drilling are based on our risked assessment of the projects. Production estimates include the impact of downtime based on historical trends. Due to the high volume production from certain of our gas wells in Louisiana, downtime resulting from operational, weather and other issues make production from this area volatile and could cause our production to be lower than the estimated levels. |
Production estimates reflect the sale of certain non-core assets effective in the fourth quarter of 2003. Effective October 1, 2003, we sold our interest in 27 predominantly non-operated fields producing approximately 450 net equivalent barrels per day. Effective November 1, 2003 we sold our interest in nine predominantly non-operated fields producing approximately 350 net equivalent barrels per day. We are evaluating the sale of our interests in Illinois which are currently producing approximately 2,300 net equivalent barrels per day. If we sell the Illinois interests, production will be lower than the estimates provided.
| | 2. | Estimated oil price differentials. Our realized wellhead oil price is lower than the NYMEX index level as a result of area and quality differentials. We have locked in a fixed price differential to NYMEX on approximately 65% of our oil production for the fourth quarter of 2003. |
| | 3. | 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. |
| | 4. | 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 our producing properties. Actual expenses may vary from the estimates provided due to the level of repair and work over 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 our production expenses that do not decrease if production levels decline. |
| | 5. | Production and ad valorem taxes. Production and ad valorem taxes include (1) ad valorem taxes that are assessed on an annual basis based on the property value determined by the taxing authority and (2) 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 $5.05 per Mcf for the fourth quarter. |
| | 6. | Stock appreciation rights. The G&A estimates provided exclude any expense related to stock appreciation rights, which are subject to variable accounting. As a result, our results of operations will be affected by fluctuations in the price of our common stock. |
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At the end of each quarter we compare the per share closing price of our 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 quarter. This means that for accounting purposes, vesting occurs ratably over the vesting period. To the extent the closing price at the end of each period exceeds the exercise price, we recognize the excess as compensation expense to the extent not previously recognized. If the quarter-end closing price decreases compared to prior periods, we reduce compensation expense to the extent previously recognized. As of September 30, 2003 we had approximately 4.1 million SARs outstanding with an average exercise price of $9.19, of which 2.7 million of the SARs were vested or deemed vested. We will incur cash expenditures as SARs are exercised, but our common shares outstanding will not increase.
| | 7. | 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 conversion and integration, moving and relocation related to consolidation of office locations and certain severance and relocation costs. We expect that merger related costs will be approximately $1.5 million to $2.0 million in the fourth quarter and will total $4.5 million to $5.0 million in 2003. These costs are not included in the G&A estimates provided because the amounts are difficult to estimate and we do not consider these expenses as a recurring cost of ongoing operations. |
| | 8. | DD&A—oil and gas. Our oil and gas DD&A rate is approximately $4.00 per BOE. The fourth quarter DD&A rate will be adjusted based on year-end 2003 proved reserve volumes. Our rate of recording DD&A is dependent upon our estimate of proved reserves including future development and abandonment costs as well as our level of capital spending. If the estimates of proved reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower oil and gas prices, which may make it uneconomic for us to drill and produce some of our reserves. In addition, increases in costs required to develop our reserves would increase the rate at which we record DD&A expense. We are unable to predict changes in future development costs as such costs are dependent of the success of our exploration and development program, as well as future economic conditions. |
| | 9. | Accretion of asset retirement obligation. Effective January 1, 2003 we 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 capitalizes 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 we included estimated future costs of abandonment and dismantlement in our full cost amortization base and these costs were amortized as a component of depletion expense. |
| | 10. | Interest expense. Our interest expense will consist of interest on: |
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| | a. | $275 million of 8.75% Senior Subordinated Notes. Interest expense for the fourth quarter for this debt will be $6.0 million, including amortization of related premium and discount. |
| | b. | Amounts outstanding under our $500 million revolving credit facility. The revolving credit facility provides for grid pricing at LIBOR or Prime at our 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. | We have an interest rate swap agreement that expires in October 2004 under which we receive LIBOR and pay 3.9% on a notional amount of $7.5 million. |
| | d. | Interest expense will be reduced by capitalized interest. We estimate we will capitalize approximately $1.2 million of interest in the fourth quarter of 2003. |
| | 11. | Book Tax Rate. We estimate that our 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. Our deferred and current tax rates are based on current estimates of taxable income. |
| | 12. | Weighted average equivalent shares outstanding. Estimated basic shares outstanding are based on shares outstanding on September 30, 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. We do not have any outstanding stock options or warrants. |
| | 13. | Write-downs under full cost ceiling test rules. Under the SEC’s full cost accounting rules, we review the carrying value of our 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 we price our future oil and gas production at the prices in effect at the end of each fiscal quarter and require a write-down if our capitalized costs exceed the “ceiling” even if prices decline for only a short period of time. We have had no write-downs due to these ceiling test limitations since 1998. Given the volatility of oil and gas prices, it is likely that our 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 our oil and gas properties |
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could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.
| | 14. | Goodwill. We recorded approximately $147 million of goodwill in connection with the 3TEC acquisition. Goodwill represents the excess of the purchase price paid by us 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: November 6, 2003 | | | | /s/ Cynthia A. Feeback
|
| | | | | | | Cynthia A. Feeback Senior Vice President-Accounting and Treasurer |
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