PXP REPORTS THIRD-QUARTER 2011 RESULTS,

RECORD QUARTERLY SALES VOLUMES OF 104.4 THOUSAND BARRELS OF OIL EQUIVALENT PER DAY,

15% GROWTH IN TOTAL PRODUCTION YEAR-OVER-YEAR,

9% GROWTH IN LIQUIDS PRODUCTION YEAR-OVER-YEAR DUE PRIMARILY TO STRONG EAGLE FORD PERFORMANCE, AND

ENTERS INTO AGREEMENTS TO DIVEST ITS TEXAS PANHANDLE AND CONVENTIONAL NATURAL GAS SOUTH TEXAS PROPERTIES FOR $785 MILLION

News provided by

Plains Exploration & Production Company

Nov 04, 2011, 07:01 ET

HOUSTON, Nov. 4, 2011 /PRNewswire/ --

Third-Quarter Statistical Highlights:

  • Revenues of $501.8 million.
  • Net loss of $88.3 million, or $0.62 per diluted share.
  • Adjusted net income of $64.9 million, or $0.45 per diluted share (a non-GAAP measure).
  • Income from operations of $168.6 million, a 74% increase over third-quarter 2010.
  • Net cash provided by operating activities of $345.2 million, a 70% increase over third-quarter 2010.
  • Average daily sales volumes of approximately 104.4 thousand barrels of oil equivalent (BOE), a 15% increase compared to third-quarter 2010 or 26% increase pro-forma for the 2010 asset sale.
  • Average daily liquids sales volumes of approximately 50.9 thousand barrels of oil, a 9% increase compared to third-quarter 2010 or 16% pro-forma for the 2010 asset sale.
  • Total production costs per BOE of $13.84, a 3% decrease from third-quarter 2010.
  • Gross margin per BOE of $21.35 and cash margin per BOE of $36.73 (a non-GAAP measure), an increase of 27% and 18% over third-quarter 2010, respectively.

Plains Exploration & Production Company (NYSE: PXP) ("PXP" or the "Company") announces 2011 third-quarter financial and operating results and files full-year 2012 operational guidance with the SEC on a Form 8-K.

FINANCIAL SUMMARY

PXP reports third-quarter revenues of $501.8 million and net loss of $88.3 million, or $0.62 per diluted share, compared to revenues of $387.8 million and net income of $18.8 million, or $0.13 per diluted share, for the third-quarter 2010. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on PXP's mark-to-market derivative contracts, a $395.5 million unrealized loss on investment in McMoRan Exploration Co. ("McMoRan") common stock, and other items. When considering these items, net income for the third-quarter 2011 was $64.9 million, or $0.45 per diluted share (a non-GAAP measure), compared to $41.4 million, or $0.29 per diluted share, for the third-quarter 2010.

PXP owns 51 million shares of McMoRan common stock and measures the equity investment at fair value as determined by the stock's closing price discounted for certain restrictions on the marketability of the shares. The change in fair value of the investment is recognized as a gain or loss on investment on the income statement. On September 30, 2011, the McMoRan shares were valued at approximately $379.4 million, based on McMoRan's closing stock price of $9.93 as compared to a fair value of $774.9 million on June 30, 2011 based on McMoRan's closing stock price of $18.48, which resulted in the unrealized loss of $395.5 million for the quarter. McMoRan's closing stock price on November 3, 2011 was $12.92.

For the first nine months of 2011, PXP reports revenues of $1.4 billion and net income of $107.6 million, or $0.75 per diluted share, compared to revenues of $1.1 billion and net income of $122.8 million, or $0.87 per diluted share, for the same period in 2010. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on PXP's mark-to-market derivative contracts, an unrealized loss on investment in McMoRan common stock, a 2010 impairment of PXP's relinquished Vietnam oil and gas properties, and other items. When considering these items, net income for the first nine months of 2011 was $194.5 million, or $1.36 per diluted share (a non-GAAP measure), compared to $121.9 million, or $0.86 per diluted share, for the same period in 2010.

A reconciliation of non-GAAP financial measures used in this release to comparable GAAP financial measures is included with the financial tables.

OPERATIONAL UPDATE

In the Eagle Ford, PXP has 5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. One additional rig is expected to begin operations in December. The Company continues to see strong drilling results. Initial production rates on recently completed wells are as follows:


The Dougherty #1H achieved peak rate of 2,579 gross BOE per day (100% working interest).

The Dougherty #2H achieved peak rate of 2,212 gross BOE per day (100% working interest).

The Deleon-Reinhard Unit #1H achieved peak rate of 2,435 gross BOE per day (50% working interest).

The Deleon-Wiatrek Unit #1H achieved peak rate of 2,444 gross BOE per day (50% working interest).




Third-quarter daily sales volumes averaged approximately 5,170 BOE per day net to PXP, compared to 2,330 BOE per day net to PXP in the second-quarter 2011. For the month of October, daily sales volumes averaged approximately 9,600 BOE per day net to PXP, and the Company expects to exit the year above 10,000 BOE net per day. The Company continues to expand infrastructure and expects to complete a total of 12 planned production handling facilities through 2012.

In California, PXP has 3 drilling rigs operating onshore where PXP continues its multi-year development program in the Los Angeles and San Joaquin Basins. Year-to-date drilling results are in-line with expectations, sales volumes are consistently strong and the large operating margin is improving due to higher liquid price realizations. Third-quarter daily sales volumes onshore and offshore averaged 39,700 BOE per day net to PXP and are expected to be above 40,000 BOE net per day by year-end 2011.

In the Haynesville Shale, PXP's primary operator is currently operating 21 rigs down from 31 rigs reported in August 2011. Third-quarter daily sales volumes averaged approximately 201.3 million cubic feet equivalent (MMcfe) per day net to PXP compared to 181.7 MMcfe per day net to PXP in the second-quarter 2011. The rate of increase in sales volumes is anticipated to slow as the rig count continues to decline over the remainder of this year.

James C. Flores, Chairman, President and CEO of PXP commented, "Once again, PXP delivered solid quarterly operating results with production, income from operations and cash margin per BOE all considerably stronger than a year ago. These results reflect higher commodity prices, the successful execution of our strategic plan and the strength of PXP's core assets. We expect a robust finish to the year as operational momentum builds in the Eagle Ford. We have taken a number of steps recently to enhance PXP's asset intensity, characterized by assets with longer reserve life, abundant inventory and high cash margins. The announced asset sales will allow PXP to use the sales proceeds to move forward on our interest savings target and redirect capital to higher intensity assets. The Company's growing onshore oil business combined with PXP's well-capitalized Gulf of Mexico oil business, anchored by the Lucius oil field development, is expected to increase total company oil/liquids sales volumes at greater than 15% compounded average growth rate through 2016."

ASSET SALES

PXP announced today that it and certain of its subsidiaries have entered into definitive purchase and sale agreements to sell all of its working interests in oil and gas properties located in the Texas Panhandle and its conventional natural gas properties in South Texas for $785 million cash. Proceeds are expected to reduce debt.

PXP agreed to sell all of its working interests in its Texas Panhandle properties to an affiliate of Linn Energy, LLC (NASDAQ: LINE) for $600 million. PXP's aggregate working interest in the Texas Panhandle properties generated total sales volumes of approximately 84 MMcfe per day during the third quarter of 2011 and had 263 billion cubic feet equivalent (Bcfe) of estimated proved reserves as of December 31, 2010. This sale is expected to close in December 2011 with an effective date of November 1, 2011. Barclays Capital Inc. acted as financial advisor to PXP and J.P. Morgan Securities LLC rendered a fairness opinion on this transaction.

PXP also agreed to sell all of its working interests in its South Texas conventional natural gas properties to a third party for $185 million. PXP's aggregate working interest in these properties generated total sales volumes of approximately 39 MMcfe per day during the third quarter of 2011 and had 120 Bcfe of estimated proved reserves as of December 31, 2010. This sale is expected to close in December 2011 with an effective date of September 1, 2011. Barclays Capital Inc. acted as financial advisor to PXP and Simmons & Company International rendered a fairness opinion on this transaction.

Winston M. Talbert, Executive Vice President and Chief Financial Officer of PXP commented, "The asset sales are part of a broader strategy to increase revenues through the previously announced marketing contracts, decrease deferred premium costs through the previously announced derivative enhancements, and lower total interest costs by lowering debt levels. Over the next eighteen months, PXP has $2.1 billion of high coupon debt that is callable. With the current low interest rate environment, PXP sees a unique opportunity to reduce its interest costs 30% to 40% by year-end 2012 thereby increasing profitability, shareholder return and cash flow."

CONFERENCE CALL

PXP will host a conference call today, Friday, November 4, 2011 at 8:00 a.m. Central time. Investors wishing to participate in the conference call may dial 1-800-567-9836 or 1-973-935-8460. The conference call and replay ID is: 17181828. The replay can be accessed by dialing 1-855-859-2056 or 1-404-537-3406. A live webcast of the conference call and a slide presentation will be available in the Investor Information section of PXP's website at www.pxp.com.

ANALYST MEETING

PXP will host its 2011 Analyst Meeting on Tuesday, November 15, 2011, beginning at 1:30 p.m. Central Time. Links to the live webcast and presentation materials will be available in the Investor Information section of PXP's website, www.pxp.com, with a webcast replay available following the meeting.

PXP is an independent oil and gas company primarily engaged in the activities of acquiring, developing, exploring and producing oil and gas in California, Texas, Louisiana, and the Gulf of Mexico. PXP is headquartered in Houston, Texas.

ADDITIONAL INFORMATION & FORWARD-LOOKING STATEMENTS

This press release contains forward-looking information regarding PXP that is intended to be covered by the safe harbor "forward-looking statements" provided by the Private Securities Litigation Reform Act of 1995. All statements included in this press release that address activities, events or developments that PXP expects, believes or anticipates will or may occur in the future are forward-looking statement. These include statements regarding:


* completion of the proposed asset sales,

* completion of the deepwater financing,

* reserve and production estimates,

* oil and gas prices,

* the impact of derivative positions,

* production expense estimates,

* cash flow estimates,

* future financial performance,

* capital and credit market conditions,

* planned capital expenditures, and

* other matters that are discussed in PXP's filings with the SEC.




These statements are based on our current expectations and projections about future events and 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. Please refer to our filings with the SEC, including our Form 10-K, for a discussion of these risks.

All forward-looking statements in this press release are made as of the date hereof, and you should not place undue reliance on these statements without also considering the risks and uncertainties associated with these statements and our business that are discussed in this press release and our other filings with the SEC. 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 law, we do not intend to update these forward-looking statements and information.


Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)
















Three Months Ended


Nine Months Ended





September 30,


September 30,





2011


2010


2011


2010







(Unaudited)



Revenues









Oil sales

$ 379,079


$ 276,423


$ 1,110,228


$ 828,690


Gas sales

121,014


110,510


331,486


305,927


Other operating revenues

1,755


890


5,233


1,849





501,848


387,823


1,446,947


1,136,466

Costs and Expenses









Lease operating expenses

79,987


67,668


234,380


187,707


Steam gas costs

17,015


17,146


49,641


52,166


Electricity

10,112


10,093


30,203


31,242


Production and ad valorem taxes

10,636


9,082


39,084


21,357


Gathering and transportation expenses

15,237


15,311


44,825


37,642


General and administrative

28,158


34,278


94,964


101,969


Depreciation, depletion and amortization

167,894


133,207


453,194


379,410


Impairment of oil and gas properties

-


-


-


59,475


Accretion

4,307


4,420


12,878


13,238


Legal recovery

-


-


-


(8,423)


Other operating income

(50)


(467)


(657)


(4,981)





333,296


290,738


958,512


870,802












Income from Operations

168,552


97,085


488,435


265,664

Other (Expense) Income









Interest expense

(43,495)


(26,514)


(113,141)


(75,606)


Debt extinguishment costs

-


(461)


-


(1,189)


Gain (loss) on mark-to-market derivative contracts

125,551


(42,600)


93,467


23,240


Loss on investment measured at fair value

(395,490)


-


(284,929)


-


Other income

1,399


1,704


2,949


14,245

(Loss) Income Before Income Taxes

(143,483)


29,214


186,781


226,354


Income tax benefit (expense)










Current

26,718


75,169


25,959


67,759



Deferred

28,469


(85,535)


(105,165)


(171,362)

Net (Loss) Income

$ (88,296)


$   18,848


$    107,575


$ 122,751

(Loss) Earnings per Share









Basic

$     (0.62)


$       0.13


$          0.76


$       0.87


Diluted

$     (0.62)


$       0.13


$          0.75


$       0.87

Weighted Average Shares Outstanding









Basic

141,826


140,601


141,500


140,304


Diluted

141,826


141,609


143,351


141,706





Plains Exploration & Production Company






Operating Data










Three Months Ended


Nine Months Ended





September 30,


September 30,





2011


2010


2011


2010







(Unaudited)



Daily Average Volumes









Oil and liquids sales (Bbls)

50,891


46,478


47,853


45,702


Gas (Mcf)










Production

327,248


270,072


299,423


252,635



Used as fuel

5,962


5,396


5,875


5,327



Sales

321,286


264,676


293,548


247,308


BOE











Production

105,432


91,490


97,756


87,807



Sales

104,438


90,591


96,777


86,920

Unit Economics (in dollars)









Average NYMEX Prices










Oil

$     89.54


$     76.21


$        95.47


$     77.69



Gas

4.20


4.39


4.20


4.57


Average Realized Sales Price Before Derivative Transactions










Oil (per Bbl)

$     80.96


$     64.65


$        84.98


$     66.42



Gas (per Mcf)

4.10


4.54


4.14


4.53



Per BOE

52.05


46.43


54.57


47.82


Cash Margin per BOE (1)










Oil and gas revenues

$     52.05


$     46.43


$        54.57


$     47.82



Costs and expenses










  Lease operating expenses

(8.32)


(8.12)


(8.87)


(7.91)



  Steam gas costs

(1.77)


(2.06)


(1.88)


(2.20)



  Electricity

(1.05)


(1.21)


(1.14)


(1.32)



  Production and ad valorem taxes

(1.11)


(1.09)


(1.48)


(0.90)



  Gathering and transportation

(1.59)


(1.84)


(1.70)


(1.59)



  Oil and gas related DD&A

(16.86)


(15.33)


(16.49)


(15.33)



Gross margin (GAAP)

21.35


16.78


23.01


18.57




Oil and gas related DD&A

16.86


15.33


16.49


15.33




Realized loss on derivative instruments

(1.48)


(0.89)


(1.63)


(1.11)



Cash margin (Non-GAAP)

$     36.73


$     31.22


$        37.87


$     32.79












Oil and gas capital expenditures accrued ($ in thousands) (2)

$ 502,745


$ 273,182


$ 1,364,142


$ 781,351
















(1)

Cash margin per BOE (a non-GAAP measure) is calculated by adjusting gross margin per BOE (a GAAP measure) to include the realized gain and loss on derivative instruments and to exclude DD&A.  Management believes this presentation may be helpful to investors as it represents the cash generated by our oil and gas production that is available for, among other things, capital expenditures and debt service.  PXP management uses this information to analyze operating trends for comparative purposes within the industry.  This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating trends and performance.  












(2)

Additions to oil and gas properties reported in our consolidated statement of cash flows differ from the accrual basis amounts reflected above due to the timing of cash payments.  Excludes acquisitions.




















Plains Exploration & Production Company






Reconciliation of GAAP to Non-GAAP Measure

























Three Months Ended September 30, 2011




Oil


Gas


BOE




(per Bbl)


(per Mcf)




Average Realized Sales Price















Average realized price before derivative instruments (GAAP)  (1)

$   80.96


$      4.10


$ 52.05



Realized (loss) gain on derivative instruments

(3.13)


0.01


(1.48)










Realized cash price including derivative settlements (non-GAAP)

$   77.83


$      4.11


$ 50.57




















Three Months Ended September 30, 2010




Oil


Gas


BOE




(per Bbl)


(per Mcf)




Average Realized Sales Price















Average realized price before derivative instruments (GAAP)  (1)

$   64.65


$      4.54


$ 46.43



Realized (loss) gain on derivative instruments

(4.18)


0.43


(0.89)










Realized cash price including derivative settlements (non-GAAP)

$   60.47


$      4.97


$ 45.54




















Nine Months Ended September 30, 2011




Oil


Gas


BOE




(per Bbl)


(per Mcf)




Average Realized Sales Price















Average realized price before derivative instruments (GAAP)  (1)

$   84.98


$      4.14


$ 54.57



Realized (loss) gain on derivative instruments

(3.38)


0.01


(1.63)










Realized cash price including derivative settlements (non-GAAP)

$   81.60


$      4.15


$ 52.94




















Nine Months Ended September 30, 2010




Oil


Gas


BOE




(per Bbl)


(per Mcf)




Average Realized Sales Price















Average realized price before derivative instruments (GAAP)  (1)

$   66.42


$      4.53


$ 47.82



Realized (loss) gain on derivative instruments

(4.25)


0.40


(1.11)










Realized cash price including derivative settlements (non-GAAP)

$   62.17


$      4.93


$ 46.71











(1)

Excludes the impact of production costs and expenses and DD&A.



















Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(in thousands of dollars)



Nine Months Ended



September 30,



2011


2010



(Unaudited)

CASH FLOWS FROM OPERATING ACTIVITIES




Net income

$   107,575


$   122,751

Items not affecting cash flows from operating activities





Depreciation, depletion, amortization and accretion

466,072


392,648


Impairment of oil and gas properties

-


59,475


Deferred income tax expense

105,165


171,362


Debt extinguishment costs

-


1,189


Gain on mark-to-market derivative contracts

(93,467)


(23,240)


Loss on investment measured at fair value

284,929


-


Non-cash compensation

27,257


36,356


Other non-cash items

(6,332)


2,467

Change in assets and liabilities from operating activities

31,451


(85,836)

Net cash provided by operating activities

922,650


677,172

CASH FLOWS FROM INVESTING ACTIVITIES




Additions to oil and gas properties

(1,261,196)


(805,744)

Acquisition of oil and gas properties (1)

(36,750)


35,350

Proceeds from sales of oil and gas properties, net of costs and expenses

11,987


6,350

Derivative settlements

(47,448)


(23,546)

Additions to other property and equipment

(9,454)


(7,115)

Other

1,552


-

Net cash used in investing activities

(1,341,309)


(794,705)

CASH FLOWS FROM FINANCING ACTIVITIES




Borrowings from revolving credit facilities

4,026,900


1,486,610

Repayments of revolving credit facilities

(4,191,900)


(1,636,610)

Proceeds from issuance of Senior Notes

600,000


300,000

Costs incurred in connection with financing arrangements

(11,320)


(22,649)

Other

9


31

Net cash provided by financing activities

423,689


127,382

Net increase in cash and cash equivalents

5,030


9,849

Cash and cash equivalents, beginning of period

6,434


1,859

Cash and cash equivalents, end of period

$     11,464


$     11,708















(1)

Cash inflow in 2010 is associated with an adjustment to the final settlement of the $1.1 billion payment in September 2009 related to the prepayment of the Haynesville drilling carry.

















Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)





September 30,


December 31,





2011


2010




ASSETS

(Unaudited)



Current Assets





Cash and cash equivalents

$            11,464


$            6,434


Accounts receivable

279,842


269,024


Commodity derivative contracts

49,298


-


Inventories

26,058


24,406


Deferred income taxes

19,945


74,086


Prepaid expenses and other current assets

18,466


28,937





405,073


402,887

Property and Equipment, at cost





Oil and natural gas properties - full cost method






Subject to amortization

11,821,891


9,975,056



Not subject to amortization

2,847,919


3,304,554


Other property and equipment

142,274


137,150





14,812,084


13,416,760


Less allowance for depreciation, depletion, amortization and impairment

(6,637,010)


(6,196,008)





8,175,074


7,220,752

Goodwill

535,140


535,144

Commodity Derivative Contracts

17,536


-

Investment

379,417


664,346

Other Assets

71,747


71,808





$       9,583,987


$     8,894,937











LIABILITIES AND STOCKHOLDERS' EQUITY




Current Liabilities





Accounts payable

$          369,784


$        284,628


Commodity derivative contracts

4,231


52,971


Royalties and revenues payable

86,409


70,990


Interest payable

78,881


49,127


Other current liabilities

77,767


75,973





617,072


533,689

Long-Term Debt

3,783,938


3,344,717








Other Long-Term Liabilities





Asset retirement obligation

250,896


225,571


Commodity derivative contracts

-


24,740


Other

9,227


28,205





260,123


278,516

Deferred Income Taxes

1,406,070


1,355,050

Stockholders'  Equity





Common stock

1,439


1,439


Additional paid-in capital

3,423,057


3,427,869


Retained earnings

240,291


148,620


Treasury stock, at cost

(148,003)


(194,963)





3,516,784


3,382,965





$       9,583,987


$     8,894,937




























Plains Exploration & Production Company

Summary of Open Derivative Positions

At October 1, 2011






















Average






Instrument


Daily


Average


Deferred



Period (1)


Type


Volumes


Price (2)


Premium


Index

Sales of Crude Oil Production









2011












Oct - Dec


Put options (3)


31,000 Bbls


$80.00 Floor with a $60.00 Limit


$5.023 per Bbl


WTI


Oct - Dec


Three-way collars (4)


9,000 Bbls


$80.00 Floor with a $60.00 Limit


$1.00 per Bbl


WTI







$110.00 Ceiling





2012












Jan - Dec


Three-way collars (5)


40,000 Bbls


$100.00 Floor with an $80.00 Limit


-


Brent







$120.00 Ceiling





2013












Jan - Dec


Put options (6)


22,000 Bbls


$90.00 Floor with a $70.00 Limit


$6.237 per Bbl


Brent













Sales of Natural Gas Production









2011












Oct - Dec


Three-way collars (7)


200,000 MMBtu


$4.00 Floor with a $3.00 Limit


-


Henry Hub








$4.92 Ceiling

















2012












Jan - Dec


Put options (8)


120,000 MMBtu


$4.30 Floor with a $3.00 Limit


$0.298 per MMBtu


Henry Hub


Jan - Dec


Three-way collars (9)


40,000 MMBtu


$4.30 Floor with a $3.00 Limit


-


Henry Hub








$4.86 Ceiling





















(1)

All of our derivatives are settled monthly.

(2)

The average strike prices do not reflect any premiums to purchase the put options or collars.

(3)

If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium.  If the index price is at or above $80 per barrel, we pay only the option premium.

(4)

If the index price is less than the $80 per barrel floor, we receive the difference between the $80 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium.  We pay the difference between the index price and $110 per barrel plus the option premium if the index price is greater than the $110 per barrel ceiling.  If the index price is at or above $80 per barrel but at or below $110 per barrel, we pay only the option premium.

(5)

If the index price is less than the $100 per barrel floor, we receive the difference between the $100 per barrel floor and the index price up to a maximum of $20 per barrel.  We pay the difference between the index price and $120 per barrel if the index price is greater than the $120 per barrel ceiling.  If the index price is at or above $100 per barrel but at or below $120 per barrel, no cash settlement is required.

(6)

If the index price is less than the $90 per barrel floor, we receive the difference between the $90 per barrel floor and the index price up to a maximum of $20 per barrel less the option premium.  If the index price is at or above $90 per barrel, we pay only the option premium.

(7)

If the index price is less than the $4.00 per MMBtu floor, we receive the difference between the $4.00 per MMBtu floor and the index price up to a maximum of $1.00 per MMBtu. We pay the difference between the index price and $4.92 per MMBtu if the index price is greater than the $4.92 per MMBtu ceiling.  If the index price is at or above $4.00 per MMBtu but at or below $4.92 per MMBtu, no cash settlement is required.

(8)

If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu less the option premium.  If the index price is at or above $4.30 per MMBtu, we pay only the option premium.

(9)

If the index price is less than the $4.30 per MMBtu floor, we receive the difference between the $4.30 per MMBtu floor and the index price up to a maximum of $1.30 per MMBtu.  We pay the difference between the index price and $4.86 per MMBtu if the index price is greater than the $4.86 per MMBtu ceiling.  If the index price is at or above $4.30 per MMBtu but at or below $4.86 per MMBtu, no cash settlement is required.



























Derivative Settlements







(in thousands of dollars)

















The following tables reflect cash (payments) receipts for derivatives attributable to the stated production periods.














Three Months Ended


Nine Months Ended




September 30,


September 30,




2011


2010


2011


2010











Oil sales


$                 (14,672)


$        (17,854)


$                                        (44,209)


$             (52,980)

Natural gas sales


414


10,461


1,034


26,711




$                 (14,258)


$          (7,393)


$                                        (43,175)


$             (26,269)














Plains Exploration & Production Company




Reconciliation of GAAP to Non-GAAP Measure









The following tables reconcile net income (GAAP) to adjusted net income (non-GAAP) for the three and nine months ended September 30, 2011 and 2010. Adjusted net income excludes certain items affecting the comparability of operating results and the related tax effects.  Management believes this presentation may be helpful to investors.  PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company's operational trends and performance.








Three Months Ended



September 30,



2011


2010



(millions of dollars)






Net (loss) income (GAAP)

$ (88.3)


$   18.8


Unrealized (gain) loss on mark-to-market derivative contracts

(125.6)


42.6


Realized loss on mark-to-market derivative contracts (1)

(14.3)


(7.4)


Unrealized loss on investment measured at fair value

395.5


-


Adjust income taxes (2)

(102.4)


(12.6)






Adjusted net income (non-GAAP)

$   64.9


$   41.4








Nine Months Ended



September 30,



2011


2010



(millions of dollars)






Net income (GAAP)

$ 107.6


$ 122.8


Unrealized gain on mark-to-market derivative contracts

(93.5)


(23.2)


Realized loss on mark-to-market derivative contracts (1)

(43.2)


(26.3)


Unrealized loss on investment measured at fair value

284.9


-


Impairment of oil and gas properties

-


59.5


Legal recovery

-


(8.4)


Other non-operating income

-


(8.1)


Adjust income taxes (2)

(61.3)


5.6






Adjusted net income (non-GAAP)

$ 194.5


$ 121.9















(1)

The amounts presented in the above tables differ from the adjustments reflected in the calculation of operating cash flow on the following page due to the accrued amounts reflected in the income statement versus the actual cash received or paid reflected in the consolidated statement of cash flows.






(2)

Tax rates assumed based upon adjusted earnings are 42% and 36% for the three months ended September 30, 2011 and 2010, respectively. Tax rates assumed based upon adjusted earnings are 42% and 45% for the nine months ended September 30, 2011 and 2010. Tax rates exclude the effects of nonrecurring tax related expenses and benefits.
























Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure





















The following tables reconcile Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three and nine months ended September 30, 2011 and 2010.  Management believes this presentation may be useful to investors.  PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company's ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but rather to provide additional information that may be helpful in evaluating the Company's operational trends and performance.











Operating cash flow is calculated by adjusting net income to add back certain non-cash and non-operating items, including the unrealized gain and loss on mark-to-market derivative contracts, to include derivative cash settlements for the realized gain and loss on mark-to-market derivative contracts that are classified as investing activities for GAAP purposes, to exclude the unrealized loss on the investment measured at fair value and to exclude certain items.  


















Three Months Ended


Nine Months Ended




September 30,


September 30,




2011


2010


2011


2010




(millions of dollars)


Net (loss) income

$          (88.3)


$         18.8


$        107.6


$          122.8


Items not affecting operating cash flows









 Depreciation, depletion, amortization and accretion

172.2


137.6


466.1


392.6


 Impairment of oil and gas properties

-


-


-


59.5


 Deferred income tax (benefit) expense

(28.4)


85.5


105.2


171.4


 Debt extinguishment costs

-


0.5


-


1.2


 Unrealized (gain) loss on mark-to-market derivative contracts

(125.6)


42.6


(93.5)


(23.2)


 Unrealized loss on investment measured at fair value

395.5


-


284.9


-


 Non-cash compensation

(0.8)


13.4


27.3


36.3


 Other non-cash items

(6.0)


0.8


(6.3)


2.4


Realized loss on mark-to-market derivative contracts

(17.4)


(7.4)


(47.4)


(23.5)


Legal recovery and other

-


-


-


(16.5)


Current income taxes attributable to derivative contracts

-


(7.4)


-


-












Operating cash flow (non-GAAP)

$          301.2


$       284.4


$        843.9


$          723.0






















Reconciliation of non-GAAP to GAAP measure










Operating cash flow (non-GAAP)

$          301.2


$       284.4


$        843.9


$          723.0



Legal recovery and other

-


-


-


16.5



Changes in assets and liabilities from operating activities

26.6


(96.5)


31.4


(85.8)



Realized loss on mark-to-market derivative contracts

17.4


7.4


47.4


23.5



Current income taxes attributable to derivative contracts

-


7.4


-


-












Net cash provided by operating activities (GAAP)

$          345.2


$       202.7


$        922.7


$          677.2




SOURCE Plains Exploration & Production Company