PLAINS EXPLORATION & PRODUCTION CO - FORM 8-K - EX-99.1 - PLAINS EXPLORATION & PRODUCTION COMPANY PRESS RELEASE

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8-K - FORM 8-K - PLAINS EXPLORATION & PRODUCTION CO	d246912d8k.htm

Exhibit 99.1

Plains Exploration & Production Company

700 Milam, Suite 3100, Houston, TX 77002

www.pxp.com

NEWS RELEASE

FOR IMMEDIATE RELEASE

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

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.

Houston, Texas, November 4, 2011 - 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

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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.

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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.”

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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.

Contact: Hance Myers: hmyers@pxp.com; 713.579.6291

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Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended 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

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Plains Exploration & Production Company

Operating Data

		105,432			105,432			105,432			105,432
	Three Months Ended September 30,						Nine Months Ended 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.

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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.

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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.

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Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)


	September 30, 2011			December 31, 2010
	(Unaudited)
ASSETS
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

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Plains Exploration & Production Company

Summary of Open Derivative Positions

At October 1, 2011


Period⁽¹⁾	Instrument Type	Daily Volumes	Average Price⁽²⁾	Average Deferred 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 $110.00 Ceiling	$1.00 per Bbl	WTI

2012
Jan - Dec	Three-way collars⁽⁵⁾	40,000 Bbls	$100.00 Floor with an $80.00 Limit $120.00 Ceiling	-	Brent

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 $4.92 Ceiling	-	Henry Hub

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 $4.86 Ceiling	-	Henry Hub

⁽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.

		000000000000000000000			000000000000000000000			000000000000000000000			000000000000000000000
	Three Months Ended September 30,						Nine Months Ended 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	)

Page 11

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.

Page 12

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 September 30,						Nine Months Ended 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

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