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): October 5, 2004
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
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d2-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 14d2-2(b) under the Exchange Act (17 CFR 240.13e-4(c)) |
Plains Exploration & Production Company
Table of Contents
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Items 2.02 and 7.01.Results of Operations and Financial Condition; Regulation FD Disclosure
Plains Exploration & Production Company (the “Company”, “our”, “we” or “us”) is furnishing pursuant to Item 7.01 its estimates of certain operating and financial results for the year ended December 31, 2005. In accordance with General Instruction B.2. of Form 8-K, the information presented under this Item 7.01 shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange 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
This Report on Form 8-K includes forward-looking statements based on our current expectations and projections about future events. Statements that are predictive in nature, that depend upon or refer to future events or conditions, or that include words such as “will”, “would”, “should”, “plans”, “likely”, “expects”, “anticipates”, “intends”, “believes”, “estimates”, “thinks”, “may”, and similar expressions, are forward-looking statements. These statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. These factors include, among other things:
| | • | uncertainties inherent in the development and production of oil and gas and in estimating reserves; |
| | • | unexpected difficulties in integrating our operations as a result of any significant acquisitions, including the recent acquisition of Nuevo Energy Company (“Nuevo”); |
| | • | 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 effective indemnity or insurance, and |
| | • | general economic, market, industry or business conditions. |
All forward-looking statements in this report are made as of the date hereof, and you should not place undue certainty on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this report. Moreover, although we believe the expectations reflected in the forward-looking statements are based upon reasonable assumptions, we can give no assurance that we will attain these expectations or that any deviations will not be material. 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 2005 Estimates
The following table and accompanying notes reflect current estimates of certain results for 2005 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 our 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. We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our 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
| | | | | | |
| | | Year Ended December 31, 2005
| |
| | | Base Case
| | | Excluding Operating Results of Planned
Property Sales
| |
Estimated Production Volumes | | | | | | |
Barrels of oil equivalent- MBOE per day | | 80.0 - 90.0 | | | 72.0 - 80.0 | |
% Oil | | 75 | % | | 75 | % |
% Gas | | 25 | % | | 25 | % |
| | |
Estimated Oil Price differential to NYMEX (pre-hedge) - $/Bbl | | ($4.50) - ($5.00 | ) | | ($4.60) - ($5.20 | ) |
Estimated Gas Price differential to Henry Hub (pre-hedge) - $/MMBTU | | ($0.25) -($0.30 | ) | | ($0.25) - ($0.30 | ) |
| | |
Production Costs per BOE | | | | | | |
Lease operating expenses (excluding steam gas costs and electricity) | | $5.40 - $6.00 | | | $4.35 - $4.85 | |
Steam gas costs | | $1.60 - $1.80 | | | $1.80 - $2.00 | |
Electricity | | $1.20 - $1.40 | | | $1.15 - $1.30 | |
Production and ad valorem taxes | | $0.80 - $0.95 | | | $0.85 - $1.00 | |
Gathering and transportation | | $0.35 - $0.45 | | | $0.40 - $0.50 | |
| | |
General and administrative expenses per BOE (excluding stock appreciation rights and noncash compensation) | | $1.25 - $1.50 | | | $1.25 - $1.50 | |
| | |
Book Tax Rate | | | | | | |
Current | | 2% - 3 | % | | 2% - 3 | % |
Deferred | | 28% - 32 | % | | 28% - 32 | % |
| | |
Weighted Average Equivalent shares outstanding (in thousands) | | | | | | |
Basic | | 77,000 | | | 77,000 | |
Diluted | | 78,000 | | | 78,000 | |
| | |
Capital Expenditures ($ in thousands) | | | | | | |
Operational Capital | | $250,000 - $300,000 | | | $250,000 - $300,000 | |
Capitalized G&A and Interest | | $30,000 - $35,000 | | | $26,000 - $31,000 | |
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Plains Exploration & Production Company
Notes to Operating and Financial Guidance
Note 1—Planned Property Sales
We intend to divest various non-core properties located offshore California and onshore South Texas and New Mexico. These transactions are expected to close by the end of 2004. A purchase and sale agreement has been executed with privately held Dos Cuadras Offshore Resources, LLC (“Dos Cuadras”) to sell 11 platforms in federal and state waters off the coast of California and three related onshore facilities for $112.5 million. In addition, Dos Cuadras, which currently has ownership interests in several of these properties, will assume certain decommissioning costs. As of December 31, 2003 these properties had proven developed producing reserves of approximately 26 million equivalent barrels and approximately 10 million equivalent barrels of proved developed non-producing and proved undeveloped reserves. The transaction is subject to regulatory approvals and other conditions.
Additionally, we are in the process of divesting essentially all our assets in South Texas and New Mexico. These properties had proven reserves of 5.6 million equivalent barrels as of December 31, 2003. The Company anticipates receiving cash proceeds of approximately $40 million from these sales, which will be conducted in a combination of negotiated and auction transactions.
Base case guidance estimates include our existing property base. Guidance estimates are also provided that exclude operating results from the properties that we plan to sell.
Note 2—Production Estimates
Production estimates are based on historical operating performance and trends and our 2005 capital budget that we expect to present to our Board of Directors for approval in the fourth quarter of 2004 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.
Note 3—Estimated Oil and Gas Price Differentials
Our realized wellhead oil and gas prices are lower than the NYMEX index level as a result of area and quality differentials. We have locked in an average fixed price differential to NYMEX of approximately $5.00 per barrel on approximately 20,000 barrels per day of production for 2005 under the terms of our crude oil sales contracts. In addition, substantially all of the crude oil production from the California properties acquired from Nuevo is sold under a contract that provides for pricing based on a fixed percentage of the NYMEX crude oil price for each type of crude oil produced in California. Consequently, the actual price received for production from the properties acquired from Nuevo will vary with the production mix. The average differential for 2005 results in a net realized price of 82% of NYMEX for approximately 31,000-32,000 barrels per day of Nuevo production (79% of NYMEX for approximately 24,000-25,000 barrels per day when excluding planned property sales). The differentials included in our guidance estimate assume a NYMEX price of $28.00 per barrel for 2005. Because a portion of our differentials are based on a percentage of NYMEX, lower or higher crude oil prices will result in a lower or higher differential. For example, if crude oil prices averaged $30 per barrel for 2005, our average differential would increase by approximately $0.22 per barrel. While the sales contracts do not reduce our exposure to price volatility, they do effectively eliminate the basis differential risk between the NYMEX price and the field price of our production, thereby facilitating the ability to effectively hedge our realized price.
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Approximately 75% of our gas production is sold monthly off of industry recognized, published index pricing. The remaining 25% is priced daily on the spot market. Fluctuations between the two pricing mechanisms can significantly impact the overall differential to the Henry Hub.
Note 4—Production expenses
Production expenses include salaries and benefits of personnel involved in production activities, steam gas cost, 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 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 our production expenses that does not decrease if production levels decline.
Production expenses include the cost of natural gas used to generate steam which is injected into reservoirs to facilitate the production of heavy oil from certain of our California properties. The guidance estimates provided assume a natural gas price of $5.00 per MMBtu for the cost to purchase natural gas used in steam injection. As discussed in Note 13 we have hedged the purchase cost for 18,000 MMBtu per day of the natural gas used in the steam injection. These hedges are included in the guidance estimates provided. We use approximately 34,500 MMBtu of natural gas per day in steam injection. For each $1.00 increase (decrease) in the natural gas price our steam gas cost would increase (decrease) by $0.17 per BOE ($0.19 when excluding operating results of planned property sales), net of the impact of gas purchase hedges for 2005.
Note 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. The taxes on our California properties consist primarily of ad valorem based taxes. Production taxes included in the estimates provided were calculated assuming a natural gas price of $5.00 per Mcf and a NYMEX oil price of $28.00 per barrel.
Note 6—Stock Appreciation Rights and Noncash Compensation Expense
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. 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, 2004 we had approximately 3.0 million SARs outstanding with an average exercise price of $9.94, of which 2.6 million of the SARs were deemed vested for accounting purposes. We will incur cash expenditures as SARs are exercised, but our common shares outstanding will not increase.
The G&A estimates provided exclude noncash compensation expense, primarily related to restricted stock and restricted stock units granted to officers, directors and employees of the Company.
Note 7—DD&A – Oil and Gas
Our current DD&A rate is approximately $5.93 per BOE. The 2005 DD&A rate will be adjusted based on year-end 2004 proved reserve volumes. The DD&A rate 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
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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 on the success of our exploration and development program, as well as future economic conditions.
Note 8—Interest Expense
Our interest expense will consist of interest on:
| | 1. | $275 million of 8.75% Senior Subordinated Notes due 2012. Interest expense for this debt for the year ended December 31, 2005 will be $23.9 million including amortization of related premium. |
| | 2. | $250 million of 7.125% Senior Notes due 2014. Interest expense for this debt for the year ended December 31, 2005 will be $17.9 million including amortization of related discount. |
| | 3. | 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: |
| | | | | | | | | | | | |
| | | Less than 50%
| | | 50% to 74%
| | | 75% to 89%
| | | >=90%
| |
Libor Loans | | 1.25 | % | | 1.500 | % | | 1.750 | % | | 1.875 | % |
Prime Loans | | 0.00 | % | | 0.250 | % | | 0.500 | % | | 0.625 | % |
Commitment Fee | | 0.30 | % | | 0.375 | % | | 0.375 | % | | 0.500 | % |
| | 4. | Interest expense will be reduced by capitalized interest. Interest is capitalized on oil and natural gas properties not subject to amortization and in the process of development. We estimate we will capitalize approximately $9.0 million of interest for the year ended December 31, 2005. |
Note 9—Book Tax Rate
We estimate that our total tax rate will be approximately 30-35%, consisting of a deferred tax rate of 28-32% and a currently payable rate of 2-3%. 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 assuming a natural gas price of $5.00 per Mcf and a NYMEX oil price of $28.00 per barrel. Our total tax rate including the portion currently payable would increase at higher commodity price levels.
Note 10—Weighted Average Equivalent Shares Outstanding
Estimated basic shares outstanding are based on shares outstanding on September 30, 2004. Estimated diluted shares are based on basic shares outstanding plus restricted stock, restricted stock units and stock options utilizing the treasury stock method. 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.
Note 11—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 derivatives that are designated as a hedge and that qualify for hedge accounting) 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
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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 could occur. Write-downs required by these rules do not directly impact our cash flows from operating activities.
Note 12—Goodwill
In a business purchase transaction goodwill represents the excess of the purchase price plus liabilities assumed, including deferred taxes recorded in connection with the acquisition, over the estimated fair market value of the tangible net assets acquired. In our acquisitions of 3TEC Energy (“3TEC”) and Nuevo, goodwill totaled $215 million and represented 8% of our total assets at June 30, 2004.
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. Write-downs required by these rules do not directly impact our cash flows from operating activities.
Note 13—Derivative Instruments and Hedging Activities
We actively manage our exposure to commodity price fluctuations by hedging portions of our oil and gas production through the use of derivative instruments. We do not enter into derivative instruments for speculative trading purposes. The foregoing financial guidance does not include assumptions or projections with respect to potential gains or losses related to changes in fair value recognized pursuant to SFAS 133 for derivative instruments that do not qualify for hedge accounting or that are not designated as hedges, as there is no accurate way to forecast these potential gains or losses. Absent a stable oil and gas price environment, the potential gains or losses related to SFAS 133 are likely to materially change reported net income and increase the volatility of reported net income due to non-cash mark-to-market gains or losses.
A significant portion of our derivatives do not qualify for hedge accounting because under existing accounting standards they represent “net written options”. The derivatives that do not qualify for hedge accounting consist primarily of oil price collars that we entered into by exchanging existing oil price swaps and derivatives assumed in connection with the acquisitions of 3TEC and Nuevo.
The oil and gas hedge positions included in the tables below reflect contracts in place for 2005-2008 as of the date of this report. Location and quality differentials attributable to our properties are not included in the hedge prices.
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Open Commodity Derivative Positions Designated as Cash Flow Hedges
| | | | | | | | | | | |
Period
| | Commodity
| | Instrument Type
| | Daily Volumes
| | Average Price
| | Index
|
Sales of Production | | | | | | | | | | | |
2005 | | | | | | | | | | | |
1st Quarter | | Crude oil | | Swap | | 13,000 /Barrels | | $ | 25.82 | | WTI |
2nd Quarter | | Crude oil | | Swap | | 10,000 /Barrels | | $ | 25.80 | | WTI |
1st Quarter | | Natural gas | | Swap | | 13,000 /MMBtu | | $ | 4.75 | | Waha Socal |
2nd Quarter | | Natural gas | | Swap | | 9,500 /MMBtu | | $ | 4.66 | | Waha |
3rd Quarter | | Natural gas | | Swap | | 5,000 /MMBtu | | $ | 4.40 | | Waha |
4th Quarter | | Natural gas | | Swap | | 5,000 /MMBtu | | $ | 4.40 | | Waha |
2006 | | | | | | | | | | | |
January - December | | Crude oil | | Swap | | 15,000 /Barrels | | $ | 25.28 | | WTI |
| | | | | |
Purchases of Natural Gas | | | | | | | | | | | |
2005 | | | | | | | | | | | |
January - December | | Natural gas | | Swap | | 8,000 /MMBtu | | $ | 3.85 | | Socal |
All derivative instruments are recorded on the balance sheet at fair value. Unrealized gains and losses on derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income (“OCI”), a component of stockholders’ equity. Realized gains and losses on derivative instruments for sales of production that are designated as a hedge and qualify for hedge accounting are included in oil and gas revenues in the period the hedged volumes are sold. Realized gains and losses on derivative instruments for purchases of natural gas that are designated as a hedge and qualify for hedge accounting are included in steam gas costs in the period the hedged volumes are purchased. Cash flows are reflected as a financing activity in the statement of cash flows because pursuant to SFAS 149, Amendment of SFAS 133 on Derivative Instruments and Hedging Activities, the derivative instruments are deemed to contain a significant financing element (except for cash flows for the 2006 swap which are reflected as an operating activity).
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Open Commodity Derivative Positions That Are Not Designated as Hedging Instruments
| | | | | | | | | | |
Period
| | Commodity
| | Instrument Type
| | Daily Volumes
| | Average Price
| | Index
|
Sales of Production | | | | | | | | | | |
2005 | | | | | | | | | | |
1st Quarter | | Crude oil | | Collar | | 4,300 /Barrels | | $27.00 Floor- $31.75 Ceiling | | WTI |
2nd Quarter | | Crude oil | | Collar | | 6,800 /Barrels | | $27.00 Floor- $30.40 Ceiling | | WTI |
3rd Quarter | | Crude oil | | Collar | | 14,400 /Barrels | | $26.00 Floor- $30.03 Ceiling | | WTI |
4th Quarter | | Crude oil | | Collar | | 14,000 /Barrels | | $26.00 Floor- $29.33 Ceiling | | WTI |
January - December | | Crude oil | | Collar | | 22,000 /Barrels | | $25.00 Floor- $34.76 Ceiling | | WTI |
2006 | | | | | | | | | | |
January - December | | Crude oil | | Collar | | 22,000 /Barrels | | $25.00 Floor- $34.76 Ceiling | | WTI |
2007 | | | | | | | | | | |
January - December | | Crude oil | | Collar | | 22,000 /Barrels | | $25.00 Floor- $34.76 Ceiling | | WTI |
2008 | | | | | | | | | | |
January - December | | Crude oil | | Collar | | 22,000 /Barrels | | $25.00 Floor- $34.76 Ceiling | | WTI |
For derivatives that are not designated as a hedge, the changes in fair value are recognized currently in earnings as other income (expense). Cash flows for the Company’s derivatives that are not designated as hedges are reflected as a financing activity in the statement of cash flows because pursuant to SFAS 149, Amendment of SFAS 133 on Derivative Instruments and Hedging Activities, the derivative instruments are deemed to contain a significant financing element.
Contracts for the Purchase of Natural Gas
| | | | | | | | | | | |
Period
| | Commodity
| | Instrument Type
| | Daily Volumes
| | Average Price
| | Index
|
Purchases of Natural Gas | | | | | | | | | | | |
2005 | | | | | | | | | | | |
January - December | | Natural gas | | Physical purchase | | 10,000/MMBtu | | $ | 4.19 | | Socal |
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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: October 5, 2004 | | /s/ Cynthia A. Feeback
|
| | | Cynthia A Feeback |
| | | Senior Vice President - Accounting and Controller |
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