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PXP > SEC Filings for PXP > Form 10-Q on 3-May-2012All Recent SEC Filings

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Form 10-Q for PLAINS EXPLORATION & PRODUCTION CO


3-May-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 31.6% 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.


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Recent Developments

Derivatives

During the first quarter of 2012, we converted 5,000 of the 22,000 BOPD of Brent crude oil put option contracts for 2013 to three-way collars. These modified three-way collars have a floor price of $90 per barrel with a limit of $70 per barrel and a weighted average ceiling price of $126.08, and we eliminated approximately $11 million of deferred premiums. We entered into Brent crude oil put option spread contracts on 13,000 BOPD for 2013 with a floor price of $100 per barrel and a limit of $80 per barrel and Brent three-way collars on 25,000 BOPD for 2013 that have a floor price of $100 per barrel with a limit of $80 per barrel and a weighted average ceiling price of $124.29 per barrel. Additionally, we entered into Brent crude oil put option spread contracts on 20,000 BOPD for 2014 with a floor price of $90 per barrel and a limit of $70 per barrel. We entered into natural gas swap contracts on 100,000 MMBtu per day for 2014 with an average price of $4.09 per MMBtu.

In April 2012, we entered into Brent crude oil put option spread contracts on 30,000 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 $5.594 per barrel.

Stock Repurchase Program

In January 2012, we completed the purchase of an additional 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. Subsequent to these repurchases, our Board of Directors reset the authorization to $1.0 billion of PXP common stock, all of which is available for repurchase, and extended the program until January 2016.

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 March 31, 2012, the ceiling with respect to our domestic oil and gas properties exceeded the net capitalized costs of those properties by approximately 36%.


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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. As of April 2012, the twelve-month average of the first-day-of-the-month reference price for natural gas declined from $3.73 per MMBtu at March 31, 2012 to $3.54 per MMBtu and the comparable price for oil declined from $98.04 per Bbl at March 31, 2012 to $97.67 per Bbl.

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 three months ended March 31, 2012, we reported a net loss attributable to common stockholders of $82.3 million, or $0.64 per diluted share, compared to net income of $71.0 million, or $0.49 per diluted share, for the three months ended March 31, 2011. The decrease primarily reflects a loss on our investment in McMoRan measured at fair value and a loss on mark-to-market derivative contracts partially offset by higher oil revenues. Significant transactions that affect comparisons between the periods include the divestment of our Panhandle and South Texas properties in the fourth quarter of 2011.


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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:



                                               0000000000        0000000000
                                                   Three Months Ended
                                                       March 31,
                                                 2012              2011
           Sales Volumes
           Oil and liquids sales (MBbls)            4,519             3,966
           Gas (MMcf)
           Production                              21,294            24,230
           Used as fuel                               428               521
           Sales                                   20,866            23,709
           MBOE
           Production                               8,068             8,004
           Sales                                    7,996             7,918
           Daily Average Volumes
           Oil and liquids sales (Bbls)            49,657            44,068
           Gas (Mcf)
           Production                             234,001           269,222
           Used as fuel                             4,705             5,788
           Sales                                  229,296           263,434
           BOE
           Production                              88,657            88,938
           Sales                                   87,873            87,974
           Unit Economics (in dollars)
           Average Index Prices
           ICE Brent Price per Bbl           $     118.42      $     105.51
           NYMEX Price per Bbl                     103.03             94.60
           NYMEX Price per Mcf                       2.73              4.09
           Average Realized Sales Price
           Before Derivative Transactions
           Oil (per Bbl)                     $     103.45      $      83.67
           Gas (per Mcf)                             2.56              4.08
           Per BOE                                  65.16             54.14
           Costs and Expenses per BOE
           Production costs
           Lease operating expenses          $      10.38      $       9.12
           Steam gas costs                           1.39              1.99
           Electricity                               1.42              1.23
           Production and ad valorem taxes           1.58              1.46
           Gathering and transportation              2.03              1.61
           DD&A (oil and gas properties)            21.64             16.28

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

                                             000000       000000
                                               Three Months Ended
                                                   March 31,
                                             2012             2011
                Oil derivatives            $ (5,856)       $ (15,641)
                Natural gas derivatives       15,177              620

                                           $   9,321       $ (15,021)


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Comparison of Three Months Ended March 31, 2012 to Three Months Ended March 31, 2011

Oil and gas revenues. Oil and gas revenues increased $92.4 million, to $521.0 million for 2012 from $428.6 million for 2011, primarily due to higher average realized oil prices and higher oil sales volumes partially offset by lower average realized gas prices.

Oil revenues increased $135.7 million, to $467.5 million for 2012 from $331.8 million for 2011, reflecting higher average realized prices ($78.5 million) and higher sales volumes ($57.2 million). Our average realized price for oil increased $19.78 per Bbl to $103.45 per Bbl for 2012 from $83.67 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 $118.42 per Bbl compared to $105.51 per Bbl for 2011. Oil sales volumes increased 5.6 MBbls per day to
49.7 MBbls per day in 2012 from 44.1 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 9.6 MBbls per day in 2012.

Gas revenues decreased $43.3 million, to $53.5 million in 2012 from $96.8 million in 2011, primarily reflecting lower average realized prices ($36.0 million) and lower sales volumes ($7.3 million). Our average realized price for gas was $2.56 per Mcf in 2012 compared to $4.08 per Mcf in 2011. Gas sales volumes decreased 34.1 MMcf per day to 229.3 MMcf per day in 2012 from
263.4 MMcf per day in 2011, primarily reflecting our South Texas and Panhandle properties divested in December 2011, partially offset by increased production from our Eagle Ford Shale and Haynesville Shale properties. Excluding the impact of our divestments, sales increased 28.5 MMcf per day in 2012.

Lease operating expenses. Lease operating expenses increased $10.7 million, to $83.0 million in 2012 from $72.3 million in 2011, reflecting increased production primarily at our Eagle Ford Shale and Haynesville Shale properties and higher well workovers primarily at our California properties, partially offset by our Panhandle and South Texas properties divested in December 2011.

Steam gas costs. Steam gas costs decreased $4.7 million, to $11.1 million in 2012 from $15.8 million in 2011, primarily reflecting lower cost of gas used in steam generation. In 2012, we burned approximately 4.0 Bcf of natural gas at a cost of approximately $2.77 per MMBtu compared to 4.1 Bcf at a cost of approximately $3.88 per MMBtu in 2011.

Gathering and transportation expenses. Gathering and transportation expenses increased $3.6 million, to $16.3 million in 2012 from $12.7 million in 2011, primarily reflecting increased rates and production at our Haynesville Shale properties and an increase in production from our Eagle Ford Shale properties.

General and administrative expense. G&A expense increased $2.4 million, to $38.4 million in 2012 from $36.0 million in 2011, primarily due to an increase in costs attributable to increased headcount resulting from activity supporting increased operations in the Eagle Ford Shale.

Depreciation, depletion and amortization. DD&A expense increased $43.2 million, to $177.7 million in 2012 from $134.5 million in 2011. The increase is attributable to our oil and gas depletion, primarily due to a higher per unit rate ($42.9 million). Our oil and gas unit of production rate was $21.64 per BOE in 2012 compared to $16.28 per BOE in 2011.

If gas prices decline further or remain at the current historically low price for an extended period, there is a possibility that some of our proved undeveloped natural gas reserves would not be developed in the next five years. If this occurs, these reserves could be removed from the proved undeveloped classification, which could result in an increase in our DD&A rate.


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Interest expense. Interest expense increased $12.9 million, to $45.3 million in 2012 from $32.4 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 $17.1 million and $31.1 million of interest in 2012 and 2011, respectively. The decreased capitalized interest is primarily attributable to a lower unevaluated property balance in 2012.

Loss 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 $109.1 million loss related to mark-to-market derivative contracts in the three months ended March 31, 2012, which was primarily associated with a decrease in the fair value of our crude oil derivative contracts due to increased forward prices partially offset by an increase in the fair value of our natural gas derivative contracts due to decreased forward prices. In the three months ended March 31, 2011, we recognized a $51.0 million loss related to mark-to-market derivative contracts.

(Loss) gain on investment measured at fair value. At March 31, 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 $135.9 million loss in the three months ended March 31, 2012 related to our McMoRan investment, which was primarily associated with a decrease in McMoRan's stock price. In the three months ended March 31, 2011, we recognized a $67.3 million gain related to our McMoRan investment.

Income taxes. For the three months ended March 31, 2012 and 2011, our income tax benefit was approximately 39% of pre-tax loss and our income tax expense was approximately 40% of pre-tax income, respectively. 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 first quarter of 2012 included changes to our balance of unrecognized tax benefits.

Liquidity and Capital Resources

Our liquidity may be affected by declines in oil and gas prices, an inability to access the capital and credit markets and the success of our commodity price risk management activities, which may subject us to the credit risk of the counterparties to these agreements. These situations may arise due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions that cause substantial or extended declines in oil and gas prices. Volatility and disruption in the financial and credit markets may adversely affect the financial condition of lenders in our senior revolving credit facility, the counterparties to our commodity price risk management agreements, our insurers and our oil and natural gas purchasers, including those counterparties who may have exposure to certain European sovereign debt. These market conditions may adversely affect our liquidity by limiting our ability to access the capital and credit markets.


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Our primary sources of liquidity are cash generated from our operations, our senior revolving credit facility and periodic public offerings of debt and equity. At March 31, 2012, we had approximately $588.8 million available for future secured borrowings under our senior revolving credit facility, which had commitments and a borrowing base of $1.4 billion and $2.3 billion, respectively. At March 31, 2012, Plains Offshore had $300 million available for future secured borrowings under its senior credit facility.

Under the terms of our senior revolving credit facility, the borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination and adjusted based on our oil and gas properties, reserves, other indebtedness and other factors. Our next scheduled redetermination will be on or before May 1, 2013. Declines in oil and gas prices may adversely affect our liquidity by lowering the amount of the borrowing base that lenders are willing to extend.

The commitments of each lender to make loans to us are several and not joint under our senior revolving credit facility. Accordingly, if any lender fails to make loans to us, our available liquidity could be reduced by an amount up to the aggregate amount of such lender's commitments under the credit facility. On May 3, 2012, the commitments are from a diverse syndicate of 21 lenders and no single lender's commitment represents more than 9% of the total commitments.

In January 2012, we repurchased 2.4 million common shares at an average cost of $37.02 per share totaling $88.5 million. We have $1.0 billion in authorized repurchases remaining under the program.

In April 2012, we issued $750 million of 6 1/8% Senior Notes and received approximately $737.5 million of net proceeds, after deducting the underwriting discount and offering expenses. We used the net proceeds to reduce indebtedness outstanding under our senior revolving credit facility and for general corporate purposes, including the redemption of $76.9 million aggregate principal amount of our 7% Senior Notes. See Financing Activities.

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. 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.

We have made and will continue to make substantial capital expenditures for the acquisition, development and exploration of oil and gas. Our 2012 capital budget is approximately $1.6 billion, including capitalized interest and general and administrative expenses. We intend to fund our 2012 capital budget from internally generated funds and borrowings under our senior revolving credit facility, with the portion of our 2012 budget related to Plains Offshore being funded with cash on hand. In addition, we could curtail the portion of our capital expenditures that is discretionary if our cash flows decline from expected levels.

We believe that we have sufficient liquidity through our forecasted cash flow from operations and borrowing capacity under our senior revolving credit facility, cash on hand and the Plains Offshore senior credit facility to meet our short-term and long-term normal recurring operating needs, derivative obligations, debt service obligations, contingencies, anticipated capital expenditures and preferred stock dividends of Plains Offshore. We have no near-term debt maturities. Our senior revolving credit facility matures on May 4, 2016 and the earliest maturity of our senior notes will occur on June 15, 2015.


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Working Capital

At March 31, 2012, we had working capital of approximately $657.4 million, primarily due to the current asset classification of our investment in the McMoRan common shares and cash on hand from the Plains Offshore preferred stock transaction in November 2011. Our working capital fluctuates for various reasons, including the fair value of our investment, commodity derivative instruments and stock-based compensation.

Financing Activities

Senior Revolving Credit Facility. In February 2012, our borrowing base was increased from $1.8 billion to $2.3 billion until the next scheduled redetermination date on or before May 1, 2013. The commitments remained unchanged at $1.4 billion. The borrowing base will be redetermined on an annual basis, with us and the lenders each having the right to one annual interim unscheduled redetermination, and adjusted based on our oil and gas properties, reserves, other indebtedness and other factors. We are required, among other things, to make a mandatory prepayment if the combined total borrowings under both our senior revolving credit facility and the Plains Offshore senior credit facility exceed the borrowing base. Additionally, our senior revolving credit facility contains a $250 million limit on letters of credit and a $50 million commitment for swingline loans. At March 31, 2012, we had $810.0 million in outstanding borrowings and $1.2 million in letters of credit outstanding under our senior revolving credit facility. The daily average outstanding balance for the three months ended March 31, 2012 was $838.5 million. In connection with our issuance of the 6 1/8% Senior Notes in April 2012, our lenders approved our request to reduce our existing $2.3 billion borrowing base by an amount equal to 0.25 multiplied by the principal in excess of $500 million that is not used to repay any existing Senior Notes.

Amounts borrowed under our senior revolving credit facility bear an interest rate, at our election, equal to either: (i) the Eurodollar rate, which is based on LIBOR, plus an additional variable amount ranging from 1.50% to 2.50%; (ii) a variable amount ranging from 0.50% to 1.50% plus the greater of (1) the prime rate, as determined by JPMorgan Chase Bank, (2) the federal funds rate, plus 1/2 of 1%, and (3) the adjusted LIBOR plus 1%; or (iii) the overnight federal funds rate plus an additional variable amount ranging from 1.50% to 2.50% for swingline loans. The additional variable amount of interest payable is based on the utilization rate as a percentage of (a) the total amount of funds borrowed under both our senior revolving credit facility and the Plains Offshore senior credit facility and (b) the borrowing base under our senior revolving credit facility. Letter of credit fees under our senior revolving credit facility are based on the utilization rate and range from 1.50% to 2.50%. Commitment fees range from 0.375% to 0.50% of amounts available for borrowing.

Our senior revolving credit facility is secured by 100% of the shares of stock in certain of our domestic subsidiaries, 65% of the shares of stock in certain foreign subsidiaries and mortgages covering at least 75% of the total present value of our domestic proved oil and gas properties. Our senior revolving credit facility contains negative covenants that limit our ability, as well as the ability of our restricted subsidiaries to, among other things, incur additional . . .

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