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

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Exhibit 99.1

LOGO

Plains Exploration & Production Company

700 Milam, Suite 3100, Houston, TX 77002

www.pxp.com

NEWS RELEASE

FOR IMMEDIATE RELEASE

PXP REPORTS SECOND-QUARTER 2011 NET INCOME OF

$125 MILLION OR 87 CENTS PER DILUTED SHARE AND

15% GROWTH IN YEAR-OVER-YEAR PRODUCTION

PXP ANNOUNCES EAGLE FORD SHALE FLOW RATES FROM THE CARMODY #1 AND

CARMODY #2 WELLS AT THE COMBINED INITIAL PRODUCTION RATE OF 2,919 NET

BARRELS OF OIL EQUIVALENT PER DAY

Second-Quarter Highlights:

•

Revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share.

•

Adjusted net income of $77.1 million, or $0.54 per diluted share (a non-GAAP measure).

•

Income from operations of $186.1 million.

•

Net cash provided by operating activities of $287.5 million.

•

Operating cash flow of $299.6 million (a non-GAAP measure).

•

Average daily sales volumes of approximately 97.7 thousand barrels of oil equivalent (BOE), a 15% increase compared to second-quarter 2010 or 27% increase pro-forma for the 2010 asset sale.

•

Average daily liquids sales volumes increased 7% compared to second-quarter 2010 or 12% pro-forma for the 2010 asset sale and are expected to increase ratably throughout the rest of the year.

•

Crude oil price realization of 88%.

•

Executed crude oil contracts significantly improving differentials.

•

Total production costs per BOE of $16.09.

•

Gross margin per BOE was $25.31 and cash margin per BOE was $39.92 (a non-GAAP measure).

Houston, Texas, August 4, 2011 - Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2011 second-quarter financial and operating results.

FINANCIAL SUMMARY

PXP reports second-quarter revenues of $514.8 million and net income of $124.9 million, or $0.87 per diluted share, compared to revenues of $364.6 million and net income of $45.4 million, or $0.32 per diluted share, for the second-quarter 2010. These results include certain items affecting comparability of operating results. These items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, an unrealized gain on investment, and other items. When considering these items, net income for the second-quarter 2011 was $77.1 million, or $0.54 per diluted share (a non-GAAP measure), compared to $36.9 million, or $0.26 per diluted share, for the second-quarter 2010.

For the first six months of 2011, PXP reports revenues of $945.1 million and net income of $195.9 million, or $1.37 per diluted share, compared to revenues of $748.6 million and net income of $103.9

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million, or $0.73 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 our mark-to-market derivative contracts, an unrealized gain on investment, and other items. When considering these items, net income for the first six months of 2011 was $129.6 million, or $0.90 per diluted share (a non-GAAP measure), compared to $80.5 million, or $0.57 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.

CRUDE OIL MARKETING UPDATE

In August, PXP executed a new marketing contract for its California crude production with ConocoPhillips (NYSE: COP). Currently PXP sells approximately 65% of its California crude oil to ConocoPhillips. The new contract covers approximately 90% of PXP’s California production, extends the dedication from January 1, 2015 to January 1, 2023 and replaces the percent of NYMEX index pricing mechanism with a market-based pricing approach beginning in 2012.

Separately, PXP executed an agreement with a third party purchaser to sell a large portion of its Eagle Ford crude oil using a Light Louisiana Sweet (LLS) based pricing mechanism.

In 2012, using the current market price outlook and the new marketing contracts, PXP currently expects full-year oil price realization to be between 101% - 103% of NYMEX. PXP expects 2012 total company liquids price realization, which includes crude oil and natural gas liquids, to be between 93% - 95% of NYMEX compared to full-year 2011 total company liquids price realization guidance range of 84% - 86%.

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, “Today’s announcement underscores the strength of our asset base and the skill of our dedicated employees as we continue to execute our plan to manage volume growth and strong margins. Compared to the second-quarter 2010 our total Company sales volumes increased 15% and liquids sales volumes increased 12%, pro-forma for the 2010 asset sale. In our Eagle Ford area, daily sales volumes are expected to more than double by year-end 2011 as operational momentum builds during the second half of the year. In each of our core asset areas, we remain focused on the execution of the onshore oil drilling and expansion plan and results continue to be positive. With higher crude volumes and stronger crude pricing, the business generated a 41% increase in operating cash flow and a 20% increase in cash margin per BOE over the second-quarter 2010. We expect these trends to continue supported by the accelerated Eagle Ford activity and the recently executed crude oil marketing contracts reflecting premium pricing to NYMEX.”

GUIDANCE UPDATE

Due primarily to our accelerated drilling activity in the Eagle Ford and a higher than originally planned rig count in the Haynesville, PXP’s Board of Directors approved an increase in 2011 capital spending which is estimated to be approximately $1.5 billion, excluding deepwater spending, up from $1.2 billion.

For the first six months, average daily sales volumes were 92.9 thousand BOE. With higher drilling activity year-to-date than originally planned in the Haynesville and the Eagle Ford, full-year 2011 average daily sales volumes are now expected to be near the upper end of a new guidance range of 97 – 100 thousand BOE per day.

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PXP expects its oil price realization for the full-year 2011 to be above the guidance range due to continued strength of California crude oil pricing relative to NYMEX West Texas Intermediate.

PXP expects lease operating expense per BOE, a component of total production cost per BOE, to be at the high end of the $7.90 - $8.30 per BOE full-year 2011 guidance range due to the increased activity in the Eagle Ford.

OPERATIONAL UPDATE

In the Texas Panhandle asset area, PXP has 5 drilling rigs operating in the Granite Wash trend and expects to continue this level of activity through 2011. Second-quarter daily sales volumes averaged approximately 13,620 BOE per day net to PXP, or 52% higher than first-quarter 2011 and 139% higher than the second-quarter 2010. Average daily sales volumes are expected to increase to approximately 17,000 BOE net per day by year-end 2011. During 2010 and early 2011, PXP built 15 production handling facilities and related infrastructure in order to support the rapid growth in sales volumes that PXP is now reporting.

In the Eagle Ford asset area, PXP has 5.5 net drilling rigs operating, up from the 3 net rig program originally planned for 2011. Second-quarter daily sales volumes averaged approximately 2,330 BOE per day net to PXP, an increase of approximately 4% to first-quarter 2011 average daily sales volumes. For the month of July, daily sales volumes averaged approximately 4,400 BOE per day net to PXP; and PXP expects to exit the year above 10,000 BOE net per day for this asset area.

The two most recent initial production test rates are as follows: The Carmody Trust 1H and the Carmody Trust 2H, both located in Karnes County, Texas, achieved an initial production rate of approximately 1,745 gross and 1,396 net BOE per day and 1,904 gross and 1,523 net BOE per day, respectively.

During the first half of this year, PXP built 4 production handling facilities and related infrastructure out of the 12 facilities currently planned through 2012 to support future sales volume growth. Each facility has the capability of supporting multiple wells and construction continues on future production facilities. Timing of right-of-way approvals temporarily slowed construction during the second quarter which slowed the process of connecting completed wells to pipelines. With many of the initial logistics resolved, PXP anticipates a ramp up in sales volumes during the second half of 2011.

In the California asset area, PXP has 3 drilling rigs operating onshore where PXP continues its active development program in the Los Angeles and San Joaquin Basins. Daily sales volumes onshore and offshore averaged 40,500 BOE per day net to PXP, or 7% higher than first-quarter 2011 and slightly higher than the second-quarter 2010. Average daily sales volumes are expected to be above 41,000 BOE net per day by year-end 2011.

In the Haynesville Shale asset area, PXP’s primary operator is currently operating 31 rigs and expects to reduce the rig count during the quarter. In addition, PXP expects 15 or more rigs run by other operators on its acreage. Second-quarter daily sales volumes averaged approximately 181.7 million cubic feet equivalent (MMcfe) per day net to PXP, or 12% higher than first-quarter 2011 and 71% higher than second-quarter 2010. The rate of increase in sales volumes is anticipated to slow as the rig count decreases later this year.

In the Wyoming Mowry Shale, PXP drilled and completed its first well in June 2011 and produced high-quality oil in small quantities. PXP drilled its second well and is in the process of completing this

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well. We will study the results of these initial wells and drill two additional wells in 2012 to further evaluate the project.

In the Gulf of Mexico asset area, the operator of the Lucius discovery, Anadarko Petroleum Corporation (NYSE: APC), recently announced the finalization of a unitization agreement with Exxon Mobil Corporation and co-owners to develop the Lucius field. Anadarko will operate the unit which includes portions of Keathley Canyon blocks 874, 875, 918 and 919 in the deepwater Gulf of Mexico. Following the unitization agreement, the Lucius interest owners entered into an agreement with the Hadrian South co-venturers whereby natural gas produced from the Hadrian South field will be processed through the Lucius facility in return for a production-handling fee and reimbursement for any required facility upgrades.

CONFERENCE CALL

PXP will host a conference call today, Thursday, August 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: 82594675. 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.

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, and Louisiana. 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:

* 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						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(Unaudited)
Revenues
Oil sales	$	399,306		$	276,263		$	731,149		$	552,267
Gas sales		113,670			87,678			210,472			195,417
Other operating revenues		1,809			652			3,478			959

		514,785			364,593			945,099			748,643

Costs and Expenses
Lease operating expenses		82,142			57,536			154,393			120,039
Steam gas costs		16,865			15,357			32,626			35,020
Electricity		10,371			11,115			20,091			21,149
Production and ad valorem taxes		16,920			3,828			28,448			12,275
Gathering and transportation expenses		16,841			12,912			29,588			22,331
General and administrative		30,783			30,301			66,806			67,691
Depreciation, depletion and amortization		150,757			123,810			285,300			246,203
Impairment of oil and gas properties		-			59,475			-			59,475
Accretion		4,314			4,407			8,571			8,818
Legal recovery		-			-			-			(8,423	)
Other operating income		(303	)		(3,945	)		(607	)		(4,514	)

		328,690			314,796			625,216			580,064

Income from Operations		186,095			49,797			319,883			168,579
Other (Expense) Income
Interest expense		(37,242	)		(28,039	)		(69,646	)		(49,092	)
Debt extinguishment costs		-			-			-			(728	)
Gain (loss) on mark-to-market derivative contracts		18,912			57,984			(32,084	)		65,840
Gain on investment measured at fair value		43,307			-			110,561			-
Other income		996			11,235			1,550			12,541

Income Before Income Taxes		212,068			90,977			330,264			197,140
Income tax expense
Current		(387	)		(2,672	)		(759	)		(7,410	)
Deferred		(86,789	)		(42,930	)		(133,634	)		(85,827	)

Net Income	$	124,892		$	45,375		$	195,871		$	103,903

Earnings per Share
Basic	$	0.88		$	0.32		$	1.39		$	0.74
Diluted	$	0.87		$	0.32		$	1.37		$	0.73
Weighted Average Shares Outstanding
Basic		141,797			140,560			141,335			140,153

Diluted		143,300			141,557			143,361			141,752

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Plains Exploration & Production Company

Operating Data


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(Unaudited)
Daily Average Volumes
Oil and liquids sales (Bbls)		48,524			45,395			46,308			45,307
Gas (Mcf)
Production		301,162			242,961			285,280			243,773
Used as fuel		5,874			5,272			5,831			5,292
Sales		295,288			237,689			279,449			238,481
BOE
Production		98,718			85,889			93,855			85,935
Sales		97,739			85,010			92,883			85,053
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	102.34		$	78.05		$	98.50		$	78.46
Gas		4.32			4.09			4.20			4.67
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	90.42		$	66.87		$	87.23		$	67.34
Gas (per Mcf)		4.23			4.05			4.16			4.52
Per BOE		57.68			47.05			56.01			48.57
Cash Margin per BOE ⁽¹⁾
Oil and gas revenues	$	57.68		$	47.05		$	56.01		$	48.57
Costs and expenses
Lease operating expenses		(9.23	)		(7.44	)		(9.19	)		(7.80	)
Steam gas costs		(1.90	)		(1.99	)		(1.94	)		(2.27	)
Electricity		(1.17	)		(1.44	)		(1.20	)		(1.37	)
Production and ad valorem taxes		(1.90	)		(0.49	)		(1.69	)		(0.80	)
Gathering and transportation		(1.89	)		(1.67	)		(1.76	)		(1.45	)
Oil and gas related DD&A		(16.28	)		(15.33	)		(16.28	)		(15.33	)

Gross margin (GAAP)		25.31			18.69			23.95			19.55
Oil and gas related DD&A		16.28			15.33			16.28			15.33
Realized losses on derivative instruments		(1.67	)		(0.84	)		(1.72	)		(1.23	)

Cash margin (Non-GAAP)	$	39.92		$	33.18		$	38.51		$	33.65

Oil and gas capital expenditures accrued ($ in thousands) ⁽²⁾	$	472,056		$	284,753		$	861,397		$	508,169

⁽¹⁾

Cash margin per BOE (a non-GAAP measure) is calculated by adjusting gross margin per BOE (a GAAP measure) to include realized gains and losses 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 June 30, 2011
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾	$	90.42		$	4.23	$	57.68
Realized losses on derivative instruments		(3.36	)		-		(1.67	)


Realized cash price including derivative settlements (non-GAAP)	$	87.06		$	4.23	$	56.01


	Three Months Ended June 30, 2010
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾	$	66.87		$	4.05	$	47.05
Realized (losses) gains on derivative instruments		(4.27	)		0.52		(0.84	)


Realized cash price including derivative settlements (non-GAAP)	$	62.60		$	4.57	$	46.21


	Six Months Ended June 30, 2011
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾	$	87.23		$	4.16	$	56.01
Realized (losses) gains on derivative instruments		(3.52	)		0.01		(1.72	)


Realized cash price including derivative settlements (non-GAAP)	$	83.71		$	4.17	$	54.29


	Six Months Ended June 30, 2010
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP) ⁽¹⁾	$	67.34		$	4.52	$	48.57
Realized (losses) gains on derivative instruments		(4.28	)		0.38		(1.23	)


Realized cash price including derivative settlements (non-GAAP)	$	63.06		$	4.90	$	47.34

⁽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)


	Six Months Ended
	June 30,
	2011			2010
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	195,871		$	103,903
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		293,871			255,021
Impairment of oil and gas properties		-			59,475
Deferred income tax expense		133,634			85,827
Debt extinguishment costs		-			728
Loss (gain) on mark-to-market derivative contracts		32,084			(65,840	)
Gain on investment measured at fair value		(110,561	)		-
Non-cash compensation		28,031			22,955
Other non-cash items		(302	)		1,672
Change in assets and liabilities from operating activities		4,797			10,691

Net cash provided by operating activities		577,425			474,432

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(800,170	)		(558,386	)
Acquisition of oil and gas properties⁽¹⁾		(32,456	)		43,923
Proceeds from sales of oil and gas properties, net of costs and expenses		11,987			7,230
Derivative settlements		(30,039	)		(16,153	)
Additions to other property and equipment		(6,534	)		(4,394	)

Net cash used in investing activities		(857,212	)		(527,780	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		2,679,200			860,455
Repayments of revolving credit facilities		(2,989,200	)		(1,090,455	)
Proceeds from issuance of Senior Notes		600,000			300,000
Costs incurred in connection with financing arrangements		(11,320	)		(5,932	)
Other		4			-

Net cash provided by financing activities		278,684			64,068

Net (decrease) increase in cash and cash equivalents		(1,103	)		10,720
Cash and cash equivalents, beginning of period		6,434			1,859

Cash and cash equivalents, end of period	$	5,331		$	12,579

⁽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)


	June 30,			December 31,
	2011			2010
ASSETS	(Unaudited)
Current Assets
Cash and cash equivalents	$	5,331		$	6,434
Accounts receivable		250,413			269,024
Inventories		27,166			24,406
Deferred income taxes		66,002			74,086
Prepaid expenses and other current assets		27,412			28,937

		376,324			402,887


Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		10,844,515			9,975,056
Not subject to amortization		3,309,642			3,304,554
Other property and equipment		143,684			137,150

		14,297,841			13,416,760
Less allowance for depreciation, depletion, amortization and impairment		(6,475,951	)		(6,196,008	)

		7,821,890			7,220,752

Goodwill		535,142			535,144

Investment		774,907			664,346

Other Assets		76,179			71,808

	$	9,584,442		$	8,894,937


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	315,242		$	284,628
Commodity derivative contracts		59,786			52,971
Royalties and revenues payable		82,818			70,990
Interest payable		58,446			49,127
Other current liabilities		74,338			75,973

		590,630			533,689

Long-Term Debt		3,637,447			3,344,717


Other Long-Term Liabilities
Asset retirement obligation		239,361			225,571
Commodity derivative contracts		20,400			24,740
Other		23,146			28,205

		282,907			278,516

Deferred Income Taxes		1,480,598			1,355,050

Stockholders’ Equity
Common stock		1,439			1,439
Additional paid-in capital		3,410,856			3,427,869
Retained earnings		328,624			148,620
Treasury stock, at cost		(148,059	)		(194,963	)

		3,592,860			3,382,965

	$	9,584,442		$	8,894,937

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Plains Exploration & Production Company

Summary of Open Derivative Positions

At July 1, 2011


Period ⁽¹⁾	Instrument Type	Daily Volumes	Average Price ⁽²⁾	Average Deferred Premium	Index
Sales of Crude Oil Production
2011
July - Dec	Put options⁽³⁾	31,000 Bbls	$80.00 Floor with a $60.00 Limit	$5.023 per Bbl	WTI
July - 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	Put options⁽³⁾	40,000 Bbls	$80.00 Floor with a $60.00 Limit	$6.087 per Bbl	WTI
Sales of Natural Gas Production
2011
July - Dec	Three-way collars⁽⁵⁾	200,000 MMBtu	$4.00 Floor with a $3.00 Limit $4.92 Ceiling	-	Henry Hub

2012
Jan - Dec	Put options⁽⁶⁾	160,000 MMBtu	$4.30 Floor with a $3.00 Limit	$0.294 per MMBtu	Henry Hub

⁽¹⁾	All of our derivatives are settled monthly.

⁽²⁾	The average strike prices do not reflect the cost 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 $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.

⁽⁶⁾	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.

Derivative Settlements

(in thousands of dollars)

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

		$000,000,000,000			$000,000,000,000			$000,000,000,000			$000,000,000,000
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
Oil sales	$	(14,855	)	$	(17,660	)	$	(29,537	)	$	(35,126	)
Natural gas sales		-			11,161			620			16,250

	$	(14,855	)	$	(6,499	)	$	(28,917	)	$	(18,876	)

Page 11

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

The following table reconciles net income (GAAP) to adjusted net income (non-GAAP) for the three and six months ended June 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 June 30,
	2011			2010
	(millions of dollars)
Net income (GAAP)	$	124.9		$	45.4
Unrealized gains on mark-to-market derivative contracts		(18.9	)		(58.0	)
Realized losses on mark-to-market derivative contracts⁽¹⁾		(14.9	)		(6.5	)
Unrealized gain on investment measured at fair value		(43.3	)		-
Impairment of oil and gas properties		-			59.5
Other non-operating income		-			(8.1	)
Adjust income taxes ⁽²⁾		29.3			4.6

Adjusted net income (non-GAAP)	$	77.1		$	36.9


	Six Months Ended June 30,
	2011			2010
	(millions of dollars)
Net income (GAAP)	$	195.9		$	103.9
Unrealized losses (gains) on mark-to-market derivative contracts		32.1			(65.8	)
Realized losses on mark-to-market derivative contracts⁽¹⁾		(28.9	)		(18.9	)
Unrealized gain on investment measured at fair value		(110.6	)		-
Impairment of oil and gas properties		-			59.5
Legal recovery		-			(8.4	)
Other non-operating income		-			(8.1	)
Adjust income taxes ⁽²⁾		41.1			18.3

Adjusted net income (non-GAAP)	$	129.6		$	80.5

⁽¹⁾	The amounts presented in the above table 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 43% and 53% for the three months ended June 30, 2011 and 2010, respectively. Tax rates assumed based upon adjusted earnings are 42% and 48% for the six months ended June 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 six months ended June 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 unrealized gains and losses on mark-to-market derivative contracts, to include derivative cash settlements for realized gains and losses on mark-to-market derivative contracts that are classified as investing activities for GAAP purposes, to exclude the unrealized gain on the investment measured at fair value and to exclude certain items.


	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(millions of dollars)
Net income	$	124.9		$	45.4		$	195.9		$	103.9
Items not affecting operating cash flows
Depreciation, depletion, amortization and accretion		155.1			128.2			293.9			255.0
Impairment of oil and gas properties		-			59.5			-			59.5
Deferred income tax expense		86.8			42.9			133.6			85.8
Debt extinguishment costs		-			-			-			0.7
Unrealized (gains) losses on mark-to-market derivative contracts		(18.9	)		(58.0	)		32.1			(65.8	)
Unrealized gain on investment measured at fair value		(43.3	)		-			(110.6	)		-
Non-cash compensation		11.2			6.1			28.0			23.0
Other non-cash items		(1.2	)		0.3			(0.3	)		1.7
Realized losses on mark-to-market derivative contracts		(15.0	)		(6.7	)		(30.0	)		(16.2	)
Legal recovery and other		-			(8.1	)		-			(16.5	)
Current income taxes attributable to derivative contracts		-			2.7			-			7.4


Operating cash flow (non-GAAP)	$	299.6		$	212.3		$	542.6		$	438.5


Reconciliation of non-GAAP to GAAP measure
Operating cash flow (non-GAAP)	$	299.6		$	212.3		$	542.6		$	438.5
Legal recovery and other		-			8.1			-			16.5
Changes in assets and liabilities from operating activities		(27.1	)		28.3			4.8			10.6
Realized losses on mark-to-market derivative contracts		15.0			6.7			30.0			16.2
Current income taxes attributable to derivative contracts		-			(2.7	)		-			(7.4	)

Net cash provided by operating activities (GAAP)	$	287.5		$	252.7		$	577.4		$	474.4

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