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PXP > SEC Filings for PXP > Form 10-Q on 1-Nov-2012All Recent SEC Filings

Show all filings for PLAINS EXPLORATION & PRODUCTION CO

Form 10-Q for PLAINS EXPLORATION & PRODUCTION CO


1-Nov-2012

Quarterly Report


ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following information should be read in connection with the information contained in the consolidated financial statements and notes thereto included elsewhere in this report and our Form 10-K for the year ended December 31, 2011.

Company Overview

We are an independent energy company engaged in the upstream oil and gas business. The upstream business acquires, develops, explores for and produces oil and gas. Our upstream activities are located in the United States. We own oil and gas properties with principal operations in:

Onshore California;

Offshore California;

the Gulf Coast Region;

the Gulf of Mexico; and

the Rocky Mountains.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as newer properties with development and exploration potential. We believe our balanced portfolio of assets and our ongoing risk management program position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities, including our California, Eagle Ford Shale, Haynesville Shale and Gulf of Mexico plays. Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity.

Our assets include 51.0 million shares of McMoRan common stock, approximately 31.5% of its common shares outstanding. We measure our equity investment at fair value. Unrealized gains and losses on the investment are reported in our income statement and could result in volatility in our earnings. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk - Equity Price Risk.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities and the operational performance of our producing properties. We use various derivative instruments to manage our exposure to commodity price risk. This practice may prevent us from receiving the full advantage of increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since all of our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our income statement as changes occur in the NYMEX and ICE price indices. The level of derivative activity depends on our view of market conditions, available derivative prices and our operating strategy. See Item 3 - Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.


Recent Developments

Proposed Gulf of Mexico Acquisition

On September 10, 2012, we announced that we had entered into the BP PSA to acquire from BP their interests in certain deepwater Gulf of Mexico oil and gas properties for $5.55 billion in cash, subject to customary purchase price adjustments. These properties include certain oil and gas interests in and near the Holstein, Diana, Hoover, Horn Mountain, Marlin, Dorado, King and Ram Powell fields. Certain of these properties are subject to preferential rights. The BP PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close. Under the terms of the BP PSA, we made a performance deposit of $555 million to BP, which BP will be permitted to retain as liquidated damages if it terminates the BP PSA under certain circumstances.

On September 10, 2012, we also announced that we had entered into the Shell PSA, to acquire from Shell its 50% working interest in the Holstein field for $560 million in cash, subject to customary purchase price adjustments. The Shell PSA contains customary representations and warranties, covenants, indemnification provisions and conditions to close.

We have received commitments from several financial institutions to provide financing in connection with these transactions. See Commitment Letter.

The Gulf of Mexico Acquisition is expected to close on November 30, 2012, and will be effective as of October 1, 2012. We will account for these transactions as acquisitions of businesses under purchase accounting rules.

Commitment Letter

In September 2012, we entered into the Commitment Letter to underwrite a new credit facility that will amend and restate our existing senior revolving credit facility and provide for term loan credit facilities, increase our borrowing base and provide financing and additional liquidity in connection with the Gulf of Mexico Acquisition. The Commitment Letter is subject to certain conditions, including the absence of a material adverse effect under the BP PSA, the execution of satisfactory definitive documentation and other customary closing conditions. Upon satisfaction of these conditions, the aggregate commitments of the lenders under the Amended Credit Facility will be $5.0 billion with an initial borrowing base of $5.3 billion, which includes $300 million related to the Plains Offshore Senior Credit Facility. The Amended Credit Facility will be comprised of a $3.0 billion senior secured five-year revolving credit facility, a $750.0 million senior secured five-year term loan, and a $1.25 billion senior secured seven-year term loan. Under the terms of the Commitment Letter, the lenders may also provide senior unsecured loans in an aggregate principal amount of up to $2.0 billion pursuant to the Bridge Credit Facility. Subsequently in September 2012, we successfully syndicated the Amended Credit Facility and Bridge Credit Facility to a group of banks and institutional lenders.


In connection with the closing of the Gulf of Mexico Acquisition, we expect to enter into our Amended Credit Facility on November 30, 2012. We will use the proceeds provided by the facilities to refinance certain existing indebtedness, to pay the cash consideration for the Gulf of Mexico Acquisition, to pay fees and expenses incurred in connection with the Gulf of Mexico Acquisition and related financing transactions and for general corporate purposes.

6 1/2% Senior Notes and 6 7/8% Senior Notes

In October 2012, we issued (i) $1.5 billion of 6 1/2% Senior Notes and (ii) $1.5 billion of 6 7/8% Senior Notes, both at par. We received approximately $2.95 billion of net proceeds, after deducting the underwriting discount and offering expenses. We will use the net proceeds to pay a portion of the cash consideration for the Gulf of Mexico Acquisition. Pending the closing of the Gulf of Mexico Acquisition, we intend to use a portion of the net proceeds to repay borrowings outstanding under our senior revolving credit facility. We may redeem all or part of the 6 1/2% Senior Notes and 6 7/8% Senior Notes on or after November 15, 2015 and February 15, 2018, respectively, at specified redemption prices and prior to such date at a "make-whole" redemption price.

In connection with the issuance of the 6 1/2% Senior Notes and the 6 7/8% Senior Notes, the borrowing base under our Amended Credit Facility will be reduced to $5.175 billion, which will reduce the maximum amount available to borrow under the senior secured five-year revolving credit facility to $2.875 billion from $3.0 billion. Our borrowing base for the Plains Offshore senior credit facility will remain at $300 million. In addition, as a result of the issuance of the 6 1/2% Senior Notes and the 6 7/8% Senior Notes, we will not enter into the Bridge Credit Facility.

We also obtained a consent from the majority of the lenders under our senior revolving credit facility in connection with the issuance of the 6 1/2% Senior Notes and the 6 7/8% Senior Notes, which allows the redemption feature in connection with a Mandatory Redemption Event and allows us to include such pro forma adjustments as if the transactions contemplated under the BP PSA had been consummated when calculating the ratio of debt to EBITDAX. In addition, the lenders also agreed that there would be no reduction to the borrowing base of our existing senior revolving credit facility in connection with the Senior Notes offering.

Derivatives

During the third quarter of 2012, we entered into the following Brent crude oil derivative contracts:

Brent crude oil swap contracts on 40,000 BOPD for 2013 with an average price of $109.23 per barrel.

Brent crude oil put option spread contracts on 5,000 BOPD for 2014 with a floor price of $100 per barrel, a limit of $80 per barrel and weighted average deferred premium and interest of $7.110 per barrel.

Brent crude oil put option spread contracts on 30,000 BOPD for 2014 with a floor price of $95 per barrel, a limit of $75 per barrel and weighted average deferred premium and interest of $6.091 per barrel.

Brent crude oil put option spread contracts on 25,000 BOPD for 2014 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $5.260 per barrel.

Brent crude oil put option spread contracts on 25,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $6.720 per barrel.

In October 2012, we entered into Brent crude oil put option spread contracts on 40,000 BOPD for 2015 with a floor price of $90 per barrel, a limit of $70 per barrel and weighted average deferred premium and interest of $7.019 per barrel.


General

We follow the full cost method of accounting whereby all costs associated with property acquisition, exploration and development activities are capitalized. Our revenues are derived from the sale of oil, gas and natural gas liquids. We recognize revenues when our production is sold and title is transferred. Our revenues are highly dependent upon the prices of, and demand for, oil and gas. The markets for oil and gas have historically been volatile and are likely to continue to be volatile in the future. The prices we receive for our oil and gas and our levels of production are subject to wide fluctuations and depend on numerous factors beyond our control, including supply and demand, economic conditions, foreign imports, the actions of OPEC, political conditions in other oil-producing countries, and governmental regulation, legislation and policies. Under the SEC's full cost accounting rules, we review the carrying value of our proved oil and gas properties each quarter. These rules generally require that we price our future oil and gas production at the twelve-month average first-day-of-the-month reference prices as adjusted for location and quality differentials to determine a ceiling value of our properties. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including derivative contracts that qualify and are designated for hedge accounting treatment. The derivative instruments we have in place are not classified as hedges for accounting purposes. The rules require an impairment if our capitalized costs exceed the allowed "ceiling". At September 30, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 23%.

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 in the future, impairments of our oil and gas properties could occur. Impairment charges required by these rules do not directly impact our cash flows from operating activities.

Our oil and gas production expenses include salaries and benefits of personnel involved in production activities (including stock-based compensation), steam gas costs, electricity costs, maintenance costs, production, ad valorem and severance taxes, gathering and transportation costs and other costs necessary to operate our producing properties. DD&A for producing oil and gas properties is calculated using the units of production method based upon estimated proved reserves. For the purposes of computing DD&A, estimated proved reserves are redetermined as of the end of each year and on an interim basis when deemed necessary.

G&A consists primarily of salaries and related benefits of administrative personnel (including stock-based compensation), office rent, systems costs and other administrative costs.

Results Overview

For the nine months ended September 30, 2012, we reported net income attributable to common stockholders of $87.8 million, or $0.67 per diluted share, compared to net income of $107.6 million, or $0.75 per diluted share, for the nine months ended September 30, 2011. The decrease primarily reflects increased DD&A, lower gas revenues and a smaller gain on our mark-to-market derivative contracts offset by higher oil revenues and a smaller loss on our investment in McMoRan measured at fair value. Significant transactions that affect comparisons between the periods include the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011.


Results of Operations

The following table reflects the components of our oil and gas production and
sales prices and sets forth our operating revenues and costs and expenses on a
BOE basis:



                                        Three Months Ended           Nine Months Ended
                                           September 30,               September 30,
                                        2012          2011           2012          2011
    Sales Volumes
    Oil and liquids sales (MBbls)         5,846         4,682         15,805        13,064
    Gas (MMcf)
    Production                           23,494        30,108         66,186        81,743
    Used as fuel                            309           549          1,083         1,604
    Sales                                23,185        29,559         65,103        80,139
    MBOE
    Production                            9,762         9,700         26,836        26,688
    Sales                                 9,711         9,608         26,656        26,420
    Daily Average Volumes
    Oil and liquids sales (Bbls)         63,548        50,891         57,683        47,853
    Gas (Mcf)
    Production                          255,363       327,248        241,553       299,423
    Used as fuel                          3,353         5,962          3,952         5,875
    Sales                               252,010       321,286        237,601       293,548
    BOE
    Production                          106,109       105,432         97,942        97,756
    Sales                               105,550       104,438         97,283        96,777
    Unit Economics (in dollars)
    Average Index Prices
    ICE Brent Price per Bbl           $  109.37     $  112.01     $   112.16     $  111.47
    NYMEX Price per Bbl                   92.20         89.54          96.16         95.47
    NYMEX Price per Mcf                    2.82          4.20           2.59          4.20
    Average Realized Sales Price
    Before Derivative Transactions
    Oil (per Bbl)                     $   92.44     $   80.96     $    96.64     $   84.98
    Gas (per Mcf)                          2.70          4.10           2.49          4.14
    Per BOE                               62.10         52.05          63.38         54.57
    Costs and Expenses per BOE
    Production costs
    Lease operating expenses          $   10.10     $    8.32     $    10.08     $    8.87
    Steam gas costs                        1.25          1.77           1.24          1.88
    Electricity                            1.02          1.05           1.20          1.14
    Production and ad valorem taxes        2.17          1.11           1.98          1.48
    Gathering and transportation           1.98          1.59           2.05          1.70
    DD&A (oil and gas properties)         27.21         16.86          25.54         16.49

The following table reflects cash (payments) receipts made with respect to derivative contracts during the periods presented (in thousands):

                                 Three Months Ended                 Nine Months Ended
                                    September 30,                     September 30,
                               2012             2011             2012             2011
  Oil derivatives            $   4,934       $  (17,823)       $ (8,114)       $  (48,482)
  Natural gas derivatives       14,590               414          45,499             1,034

                             $  19,524       $  (17,409)       $  37,385       $  (47,448)


Comparison of Three Months Ended September 30, 2012 to Three Months Ended September 30, 2011

Oil and gas revenues. Oil and gas revenues increased $103.0 million, to $603.1 million for 2012 from $500.1 million for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $161.3 million, to $540.4 million for 2012 from $379.1 million for 2011, reflecting greater sales volumes ($107.6 million) and average realized prices ($53.7 million). Oil sales volumes increased 12.6 MBbls per day to 63.5 MBbls per day in 2012 from 50.9 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 19.4 MBbls per day in 2012. Our average realized price for oil increased $11.48 per Bbl to $92.44 per Bbl for 2012 from $80.96 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $109.37 per Bbl compared to the average NYMEX index price of $89.54 per Bbl for 2011.

Gas revenues decreased $58.4 million, to $62.6 million in 2012 from $121.0 million in 2011, primarily reflecting lower average realized prices ($41.2 million) and sales volumes ($17.2 million). Our average realized price for gas was $2.70 per Mcf in 2012 compared to $4.10 per Mcf in 2011. Gas sales volumes decreased 69.3 MMcf per day to 252.0 MMcf per day in 2012 from
321.3 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 9.5 MMcf per day in 2012.

Lease operating expenses. Lease operating expenses increased $18.1 million, to $98.1 million in 2012 from $80.0 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, greater stock-based compensation expense resulting from an increase in the price of our common stock, increased diesel fuel cost at our Point Arguello platforms and increased well workover expense primarily at our Inglewood property, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs. Steam gas costs decreased $4.9 million, to $12.1 million in 2012 from $17.0 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.2 Bcf of natural gas at a cost of approximately $2.88 per MMBtu compared to 4.1 Bcf at a cost of approximately $4.18 per MMBtu in 2011.

Production and ad valorem taxes. Production and ad valorem taxes increased $10.5 million, to $21.1 million in 2012 from $10.6 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Gathering and transportation expense. Gathering and transportation expenses increased $4.0 million, to $19.2 million in 2012 from $15.2 million in 2011, primarily reflecting an increase in production from our Eagle Ford Shale properties and increased rates at our Haynesville Shale properties, partially offset by our Panhandle properties divested in December 2011.


General and administrative expense. G&A expense increased $11.0 million, to $39.2 million in 2012 from $28.2 million in 2011, primarily due to costs associated with the Gulf of Mexico Acquisition and greater stock-based compensation expense resulting from an increase in the price of our common stock.

Depreciation, depletion and amortization. DD&A expense increased $102.7 million, to $270.6 million in 2012 from $167.9 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to an increased per unit rate ($100.3 million). Our oil and gas unit of production rate increased to $27.21 per BOE in 2012 compared to $16.86 per BOE in 2011.

The increased DD&A rate is primarily due to the prolonged decrease in natural gas prices as some of our proved undeveloped reserves are no longer expected to be developed in the next five years. Additionally, the increase is due to impairment and transfer of certain unproved properties to cost subject to amortization.

Interest expense. Interest expense increased $15.7 million, to $59.2 million in 2012 from $43.5 million in 2011, primarily due to a decrease in interest capitalized and greater average debt outstanding partially offset by lower average interest rates. Interest expense is net of interest capitalized on oil and natural gas properties not subject to amortization but in the process of development. We capitalized $10.7 million and $27.9 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated oil and gas property balance in 2012.

(Loss) gain on mark-to-market derivative contracts. The derivative instruments we have in place are not classified as hedges for accounting purposes. Consequently, these derivative contracts are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts in our income statement. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

We recognized a $100.2 million loss related to mark-to-market derivative contracts in the third quarter of 2012, which was primarily associated with a decrease in the fair value of our crude oil and natural gas derivative contracts due to increased forward prices. In the third quarter of 2011, we recognized a $125.6 million gain related to mark-to-market derivative contracts.

Loss on investment measured at fair value. At September 30, 2012, we owned 51.0 million shares of McMoRan common stock. We are deemed to exercise significant influence over the operating and investing policies of McMoRan but do not have control. We have elected to measure our equity investment in McMoRan at fair value, and the change in fair value of our investment is recognized as loss on investment measured at fair value in our income statement.

We recognized a $43.1 million loss in the third quarter of 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan's stock price. In the third quarter of 2011, we recognized a $395.5 million loss related to our McMoRan investment.

Income taxes. For the three months ended September 30, 2012 and 2011, our income tax benefit was approximately 38% of pre-tax loss. The variance between these effective tax rates and the 35% federal statutory rate results from the tax effects of estimated annual permanent differences, including (i) expenses that are not deductible because of IRS limitations and (ii) state income taxes. In addition, specific items affecting our income tax benefit for the three months ended September 30, 2011 included a reduction to our balance of unrecognized tax benefits as a result of the expiration of the statute of limitations for a portion of our uncertain tax positions.


Comparison of Nine Months Ended September 30, 2012 to Nine Months Ended September 30, 2011

Oil and gas revenues. Oil and gas revenues increased $0.3 billion, to $1.7 billion for 2012 from $1.4 billion for 2011, primarily due to higher oil sales volumes and average realized oil prices partially offset by lower average realized gas prices and gas sales volumes.

Oil revenues increased $0.4 billion, to $1.5 billion for 2012 from $1.1 billion for 2011, reflecting greater sales volumes ($264.9 million) and average realized prices ($152.3 million). Oil sales volumes increased 9.8 MBbls per day to
57.7 MBbls per day in 2012 from 47.9 MBbls per day in 2011, primarily reflecting increased production from our Eagle Ford Shale properties, partially offset by a production decrease due to the divestment of our Panhandle properties in December 2011. Excluding the impact of our divestments, sales increased 15.4 MBbls per day in 2012. Our average realized price for oil increased $11.66 per Bbl to $96.64 per Bbl for 2012 from $84.98 per Bbl for 2011. The increase was primarily attributable to our new marketing contract effective January 1, 2012 for our California crude oil production that replaces the percent of NYMEX index pricing with a market based pricing approach. The average ICE Brent index price for 2012 was $112.16 per Bbl compared to the average NYMEX index price of $95.47 per Bbl for 2011.

Gas revenues decreased $169.4 million, to $162.1 million in 2012 from $331.5 million in 2011, primarily reflecting lower average realized prices ($131.9 million) and sales volumes ($37.5 million). Our average realized price for gas was $2.49 per Mcf in 2012 compared to $4.14 per Mcf in 2011. Gas sales volumes decreased 55.9 MMcf per day to 237.6 MMcf per day in 2012 from 293.5 MMcf per day in 2011, primarily reflecting our Panhandle and South Texas properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale properties. Excluding the impact of our divestments, sales increased 18.5 MMcf per day in 2012.

Lease operating expenses. Lease operating expenses increased $34.4 million, to $268.8 million in 2012 from $234.4 million in 2011, reflecting increased production primarily at our Eagle Ford Shale properties, increased well workover and repairs and maintenance expense primarily at our California properties and greater stock-based compensation expense resulting from an increase in the price of our common stock, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs. Steam gas costs decreased $16.7 million, to $32.9 million in 2012 from $49.6 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012 and 2011, we burned approximately 12.2 Bcf of natural gas at a cost of approximately $2.69 per MMBtu in 2012 compared to approximately $4.07 per MMBtu in 2011.

Production and ad valorem taxes. Production and ad valorem taxes increased $13.7 million, to $52.8 million in 2012 from $39.1 million in 2011, primarily reflecting increased production taxes due to increased production from our Eagle Ford Shale properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

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