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

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Exhibit 99.1

NEWS RELEASE

FOR IMMEDIATE RELEASE

PXP ANNOUNCES 2010 FOURTH-QUARTER & FULL-YEAR RESULTS

Fourth-Quarter Statistical Highlights

•

Revenues of $408.1 million and net loss of $19.5 million, or $0.14 per diluted share.

•

Adjusted net income of $28.3 million, or $0.20 per diluted share (a non-GAAP measure).

•

Net cash provided by operating activities of $235.3 million.

•

Operating cash flow of $253.6 million (a non-GAAP measure).

•

Average daily sales volumes of 93,000 barrels of oil equivalent (BOE).

Full-Year Statistical Highlights

•

Revenues of $1.5 billion and net income of $103.3 million, or $0.73 per diluted share.

•

Adjusted net income of $150.2 million, or $1.06 per diluted share (a non-GAAP measure).

•

Net cash provided by operating activities of $912.5 million, an 83% increase year-over-year.

•

Operating cash flow of $976.7 million, a 4% increase year-over-year (a non-GAAP measure).

•

Total production costs per BOE of $14.00.

•

Average daily sales volumes of 88,500 BOE, a 7% increase year-over-year.

•

Proved reserves of 416.1 million BOE, a 16% increase year-over-year.

•

All-in finding and development costs of $17.69 per BOE.

•

Finding and development costs, excluding acquisition costs, of $11.15 per BOE (a non-GAAP measure).

•

Reserve replacement ratio of 302%.

Houston, Texas, February 24, 2011 - Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2010 fourth-quarter and full-year financial and operating results.

PXP reported fourth-quarter revenues of $408.1 million and a net loss of $19.5 million, or $0.14 per diluted share, compared to revenues of $367.7 million and net income of $48.1 million, or $0.34 per diluted share, for the fourth-quarter 2009.

The fourth-quarter net loss includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts and other items. When considering these items, PXP reports net income of $28.3 million, or $0.20 per diluted share (a non-GAAP measure).

PXP reported full-year revenues of $1.5 billion and net income of $103.3 million, or $0.73 per diluted share, compared to revenues of $1.2 billion and net income of $136.3 million, or $1.09 per diluted share, for the full-year 2009.

Full-year 2010 net income includes certain items affecting the comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, an

Page 2

impairment of our Vietnam properties, a legal recovery, and other items. When considering these items, PXP reports net income for 2010 of $150.2 million, or $1.06 per diluted share (a non-GAAP measure).

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

MANAGEMENT COMMENT

James C. Flores, Chairman, President and CEO of PXP commented, “The fourth-quarter and full-year financial and operational results highlight the sound execution of our strategic plan and high-quality asset base. We navigated a challenging business environment by, once again, applying experience and innovation and remaining focused on our long-term goal of value creation. We safely grew production and reserves, increased operating cash flow, strengthened our financial position, lowered portfolio geologic risk and aggressively expanded our onshore oil resource potential.

“In response to market conditions related to the Gulf of Mexico drilling moratorium and as part of our ongoing portfolio optimization, we initiated a rigorous strategic evaluation of our Gulf of Mexico operations and determined the greatest benefit to our shareholders was to adjust our long-term operational plan to an onshore versus offshore oil growth strategy. We followed through and successfully acquired a significant position in the prolific South Texas Eagle Ford Shale play and reduced our Gulf of Mexico expenses and long lead-time capital requirements, yet retained upside exposure, by divesting our shelf assets in exchange for a combination of cash and a significant equity position in the well-capitalized McMoRan Exploration Co. The transaction was valued at over $900 million, based on December 30, 2010 closing stock price. Our previously announced deepwater portfolio divestment aimed at optimizing the value of those assets remains in process.

“With continued crude oil price strength, countered by slowly improving economic sentiment and persistently, low natural gas prices, we remain mindful of the importance to stay balanced between oil and natural gas, to protect our balance sheet and to continuously improve operating efficiencies. For 2010, we maintained our production costs relative to 2009 on a per unit basis and opportunistically entered into 2011 and 2012 crude oil and natural gas derivatives to protect the Company’s future cash flows. We ended the year with no near-term debt maturities and approximately $779 million available under our revolving credit facility.

“Our balanced, low-risk portfolio of assets, our increased exposure to onshore oil-liquids focused development, and our ongoing hedging program will serve us well in the volatile commodity price environment and allow future potential upside. These attributes, combined with our financial position and skilled and dedicated workforce, are the catalysts positioning our program to grow reserves 15% to 20% and production 10% to 15% per year on average over the next 5 years.”

PROVED RESERVES

Year-end estimated proved reserves of 416.1 million BOE were 54% oil and 46% natural gas and 57% developed and 43% undeveloped. The estimated reserves are based on the twelve-month average West Texas Intermediate oil price of $79.43 per barrel and Henry Hub natural gas price of $4.38 per million British thermal units.

In 2010, PXP added total proved reserves of 98.5 million BOE. These additions replaced 302% of 2010 production at a cost of $17.69 per BOE. Finding and development costs, excluding acquisition costs which primarily reflect the Eagle Ford property acquisition, were $11.15 per BOE.

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In 2010, we had a total of 77 million BOE of extensions and discoveries, including 54 million BOE in the Haynesville Shale resulting from successful drilling during 2010 that extended and developed the proved acreage and 17 million BOE in the Panhandle resulting from successful horizontal development of the Granite/Atoka Wash area. Positive revisions of 20 million BOE were primarily related to higher realized oil and gas prices, and proved reserve additions related to interests acquired in the Eagle Ford Shale were approximately 1 million BOE.

A summary of the Company’s proved reserve reconciliation and costs incurred for 2010 is included with the financial tables.

OPERATIONAL UPDATE

•

In the Eagle Ford Shale asset area, PXP has 4 drilling rigs operating and expects to have 4 to 6 rigs drilling on its acreage during 2011. There are 10 wells waiting on completion or connection to pipelines. Sales volume exit rates for the first quarter are expected to be in excess of 2,500 barrels of oil equivalent per day (BOEPD) net to PXP and 5,000 BOEPD net by year-end 2011. Two notable wells recently completed by PXP are as follows:

–

The Julie 1H well has been completed with an initial production rate of approximately 990 barrels of oil per day and 826 thousand cubic feet per day.

–

The Julie 2H well has been completed with an initial production rate of approximately 920 barrels of oil per day and 756 thousand cubic feet per day.

PXP has a 100% working interest and a 75% net revenue interest in these wells.

•

In our core California asset area, Platform Irene is shut-in for planned maintenance. The work began mid-January and is expected to be completed by the end of the first-quarter 2011. Onshore California, PXP continues its active development program in the Los Angeles and San Joaquin Basins. With a large resource inventory identified for this asset area, it will sustain multi-year drilling programs providing future reserves, production and free cash flow. California is PXP’s largest asset area with approximately 211 million BOE of proved reserves at year-end 2010 of which over 95% is oil. PXP maintained average daily sales volumes of approximately 40,000 BOE per day throughout 2010 and expects a 3% to 5% sales volume increase during 2011.

•

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. There are 7 wells waiting on completion or connection to pipelines. Fourth-quarter average daily sales volumes were approximately 8,000 BOE per day net to PXP. Average daily sales volumes are expected to increase to approximately 17,000 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 operate an average of 25 rigs in 2011, plus PXP expects 15 or more rigs by other operators on its acreage. Fourth-quarter average daily sales volumes were approximately 146 million cubic feet equivalent (MMcfe) net to PXP. A record daily sales volume of 155.6 MMcfe net to PXP was reached in February and average daily sales volumes are expected to increase to approximately 160 MMcfe net per day by year-end 2011.

Page 4

CONFERENCE CALL

PXP will host a conference call today, Thursday, February 24, 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: 36795961. The replay can be accessed by dialing 1-800-642-1687 or 1-706-645-9291. 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:

* the value and completion of our Gulf of Mexico deepwater divestment,

* 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.

References to quantities of oil or natural gas may include amounts that the Company believes will ultimately be produced, but that are not yet classified as “proved reserves” under SEC definitions.

All forward-looking statements in this report 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 report 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.


Investor Contact: Hance Myers		Media Contact: Scott Winters
hmyers@pxp.com; 713.579.6291		swinters@pxp.com; 713.579.6190

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Plains Exploration & Production Company

Consolidated Statements of Income

(in thousands, except per share data)


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
	(Unaudited)
Revenues
Oil sales	$	314,070		$	277,324		$	1,142,760		$	903,146
Gas sales		93,680			89,745			399,607			281,978
Other operating revenues		379			680			2,228			2,006

		408,129			367,749			1,544,595			1,187,130

Costs and Expenses
Lease operating expenses		74,826			56,352			262,533			250,916
Steam gas costs		14,283			16,376			66,449			53,801
Electricity		11,552			9,996			42,794			43,891
Production and ad valorem taxes		8,089			8,713			29,446			38,708
Gathering and transportation expenses		13,038			10,984			50,680			36,651
General and administrative		34,468			33,520			136,437			144,586
Depreciation, depletion and amortization		154,006			126,557			533,416			407,248
Impairment of oil and gas properties		—			—			59,475			—
Accretion		4,464			3,704			17,702			14,332
Legal recovery		—			—			(8,423	)		(87,272	)
Other operating expense (income)		851			583			(4,130	)		2,136

		315,577			266,785			1,186,379			904,997

Income from Operations		92,552			100,964			358,216			282,133
Other (Expense) Income
Interest expense		(31,107	)		(19,524	)		(106,713	)		(73,811	)
Debt extinguishment costs		—			—			(1,189	)		(12,093	)
Loss on mark-to-market derivative contracts		(83,935	)		(20,234	)		(60,695	)		(7,017	)
Other income		146			27,207			14,391			27,968

(Loss) Income Before Income Taxes		(22,344	)		88,413			204,010			217,180
Income tax benefit (expense)
Current		25,331			(11,334	)		93,090			(45,091	)
Deferred		(22,473	)		(28,947	)		(193,835	)		(35,784	)

Net (Loss) Income	$	(19,486	)	$	48,132		$	103,265		$	136,305

(Loss) Earnings per Share
Basic	$	(0.14	)	$	0.34		$	0.74		$	1.10
Diluted	$	(0.14	)	$	0.34		$	0.73		$	1.09
Weighted Average Shares Outstanding
Basic		140,836			139,587			140,438			124,405

Diluted		140,836			140,973			141,897			125,288

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Plains Exploration & Production Company

Operating Data (Unaudited)


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
Daily Average Volumes
Oil and liquids sales (Bbls)		46,658			46,890			45,943			48,110
Gas (Mcf)
Production		283,447			242,687			260,402			214,203
Used as fuel		5,428			5,819			5,353			6,461
Sales		278,019			236,868			255,049			207,742
BOE
Production		93,899			87,338			89,343			83,811
Sales		92,994			86,368			88,451			82,734
Unit Economics (in dollars)
Average NYMEX Prices
Oil	$	85.24		$	76.13		$	79.61		$	62.09
Gas		3.81			4.16			4.38			3.97
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)	$	73.17		$	64.28		$	68.14		$	51.43
Gas (per Mcf)		3.66			4.12			4.29			3.72
Per BOE		47.66			46.20			47.77			39.25
Cash Margin per BOE⁽¹⁾
Oil and gas revenues	$	47.66		$	46.20		$	47.77		$	39.25
Costs and expenses
Lease operating expenses		(8.75	)		(7.09	)		(8.13	)		(8.31	)
Steam gas costs		(1.67	)		(2.06	)		(2.06	)		(1.78	)
Electricity		(1.35	)		(1.26	)		(1.33	)		(1.45	)
Production and ad valorem taxes		(0.95	)		(1.10	)		(0.91	)		(1.28	)
Gathering and transportation		(1.52	)		(1.38	)		(1.57	)		(1.21	)
Oil and gas related DD&A		(17.37	)		(15.33	)		(15.87	)		(12.79	)

Gross margin (GAAP)		16.05			17.98			17.90			12.43
Oil and gas related DD&A		17.37			15.33			15.87			12.79
Realized (losses) gains on derivative instruments⁽²⁾		(0.77	)		8.19			(1.02	)		10.30

Cash margin (Non-GAAP)	$	32.65		$	41.50		$	32.75		$	35.52


Oil and gas capital expenditures accrued ($ in thousands)⁽³⁾	$	300,895		$	333,168		$	1,082,246		$	1,582,216

⁽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⁾	The 2009 realized gain excludes all cash settlements for the $106 crude oil puts and the $54 crude oil swaps monetized in the first quarter of 2009. Cash receipts on these instruments were $121.4 million prior to the $1.1 billion monetization in the first quarter 2009.

⁽³⁾	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 December 31, 2010
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP)⁽¹⁾	$	73.17		$	3.66	$	47.66
Realized (losses) gains on derivative instruments		(4.16	)		0.44		(0.77	)


Realized cash price including derivative settlements (non-GAAP)	$	69.01		$	4.10	$	46.89


	Three Months Ended December 31, 2009
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP)⁽¹⁾	$	64.28		$	4.12	$	46.20
Realized (losses) gains on derivative instruments		(2.13	)		3.41		8.19


Realized cash price including derivative settlements (non-GAAP)	$	62.15		$	7.53	$	54.39


	Twelve Months Ended December 31, 2010
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP)⁽¹⁾	$	68.14		$	4.29	$	47.77
Realized (losses) gains on derivative instruments		(4.22	)		0.41		(1.02	)


Realized cash price including derivative settlements (non-GAAP)	$	63.92		$	4.70	$	46.75


	Twelve Months Ended December 31, 2009
	Oil			Gas		BOE
	(per Bbl)			(per Mcf)
Average Realized Sales Price

Average realized price before derivative instruments (GAAP)⁽¹⁾	$	51.43		$	3.72	$	39.25
Realized gains on derivative instruments⁽²⁾		0.17			4.06		10.30


Realized cash price including derivative settlements (non-GAAP)	$	51.60		$	7.78	$	49.55

⁽¹⁾	Excludes the impact of production costs and expenses and DD&A.

⁽²⁾	The 2009 realized gain excludes all cash settlements for the $106 crude oil puts and the $54 crude oil swaps monetized in the first quarter of 2009. Cash receipts on these instruments were $121.4 million prior to the $1.1 billion monetization in the first quarter 2009.

Page 8

Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(in thousands of dollars)


	Twelve Months Ended
	December 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	103,265		$	136,305
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		551,118			421,580
Impairment of oil and gas properties		59,475			—
Deferred income tax expense		193,835			35,784
Debt extinguishment costs		1,189			12,093
Loss on mark-to-market derivative contracts		60,695			7,017
Non-cash compensation		50,875			60,490
Other non-cash items		2,594			6,950
Change in assets and liabilities from operating activities		(110,576	)		(181,173	)

Net cash provided by operating activities		912,470			499,046

CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties		(1,048,858	)		(1,628,357	)
Acquisition of oil and gas properties		(554,685	)		(1,159,939	)
Proceeds from sales of oil and gas properties, net of costs and expenses		73,965			—
Derivative settlements		(29,921	)		1,522,412
Additions to other property and equipment		(15,809	)		(14,677	)
Other		—			162

Net cash used in investing activities		(1,575,308	)		(1,280,399	)

CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities		3,332,610			3,513,325
Repayments of revolving credit facilities		(2,942,610	)		(4,588,325	)
Proceeds from issuance of Senior Notes		300,000			916,439
Costs incurred in connection with financing arrangements		(22,771	)		(19,556	)
Derivative settlements		—			1,392
Issuance of common stock		—			648,005
Other		184			57

Net cash provided by financing activities		667,413			471,337

Net increase (decrease) in cash and cash equivalents		4,575			(310,016	)
Cash and cash equivalents, beginning of period		1,859			311,875

Cash and cash equivalents, end of period	$	6,434		$	1,859

Page 9

Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)


	December 31,			December 31,
	2010			2009
ASSETS
Current Assets
Cash and cash equivalents	$	6,434		$	1,859
Accounts receivable		269,024			258,585
Commodity derivative contracts		—			11,952
Inventories		24,406			19,934
Deferred income taxes		74,086			—
Prepaid expenses and other current assets		28,937			14,305

		402,887			306,635

Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		9,975,056			9,044,146
Not subject to amortization		3,304,554			3,279,537
Other property and equipment		137,150			125,667

		13,416,760			12,449,350
Less allowance for depreciation, depletion, amortization and impairment		(6,196,008	)		(5,616,628	)

		7,220,752			6,832,722

Goodwill		535,144			535,237

Investment		664,346			—

Other Assets		71,808			60,137

	$	8,894,937		$	7,734,731

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	284,628		$	248,454
Commodity derivative contracts		52,971			59,176
Royalties and revenues payable		70,990			78,590
Interest payable		49,127			45,743
Deferred income taxes		—			153,473
Other current liabilities		75,973			97,115

		533,689			682,551

Long-Term Debt		3,344,717			2,649,689


Other Long-Term Liabilities
Asset retirement obligation		225,571			214,231
Commodity derivative contracts		24,740			—
Other		28,205			55,531

		278,516			269,762

Deferred Income Taxes		1,355,050			933,748

Stockholders’ Equity
Common stock		1,439			1,439
Additional paid-in capital		3,427,869			3,381,566
Retained earnings		148,620			51,204
Treasury stock, at cost		(194,963	)		(235,228	)

		3,382,965			3,198,981

	$	8,894,937		$	7,734,731

Page 10

Plains Exploration & Production Company

Summary of Open Derivative Positions

At January 1, 2011


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

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 twelve months ended December 31, 2010 and 2009. 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
	December 31,
	2010			2009
	(millions of dollars)
Net (loss) income (GAAP)	$	(19.5	)	$	48.1
Unrealized loss on mark-to-market derivative contracts		83.9			20.2
Realized (loss) gain on mark-to-market derivative contracts⁽¹⁾		(6.6	)		65.1
Other non-operating expense (income), net		1.6			(23.5	)
Adjust income taxes⁽²⁾		(31.1	)		(23.3	)

Adjusted net income (non-GAAP)	$	28.3		$	86.6


	Twelve Months Ended
	December 31,
	2010			2009
	(millions of dollars)
Net income (GAAP)	$	103.3		$	136.3
Unrealized loss on mark-to-market derivative contracts		60.7			7.0
Realized (loss) gain on mark-to-market derivative contracts⁽¹⁾⁽³⁾		(32.8	)		311.1
Impairment of oil and gas properties		59.5			—
Legal recovery		(8.4	)		(87.3	)
Other non-operating income, net		(6.5	)		(23.5	)
Adjust income taxes⁽²⁾		(25.6	)		(96.0	)

Adjusted net income (non-GAAP)	$	150.2		$	247.6

⁽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 50% and 42% for the three months ended December 31, 2010 and 2009, respectively. Tax rates assumed based upon adjusted earnings are 46% and 42% for the twelve months ended December 31, 2010 and 2009. Tax rates exclude the effects of nonrecurring tax related expenses and benefits.

⁽³⁾	The 2009 realized gain excludes all cash settlements for the $106 crude oil puts and the $54 crude oil swaps monetized in the first quarter of 2009. Cash receipts on these instruments were $121.4 million prior to the $1.1 billion monetization in the first quarter 2009.

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 twelve months ended December 31, 2010 and 2009. 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 either investing or financing activities for GAAP purposes and to exclude certain items.


	Three Months Ended						Twelve Months Ended
	December 31,						December 31,
	2010			2009			2010			2009
	(millions of dollars)
Net (loss) income	$	(19.5	)	$	48.1		$	103.3		$	136.3
Items not affecting operating cash flows
Depreciation, depletion, amortization and accretion		158.5			130.3			551.1			421.5
Impairment of oil and gas properties		—			—			59.5			—
Deferred income tax expense		22.5			28.9			193.8			35.8
Debt extinguishment costs		—			—			1.2			12.1
Unrealized loss on mark-to-market derivative contracts		83.9			20.2			60.7			7.0
Non-cash compensation		14.5			12.7			50.9			60.5
Other non-cash items		0.1			2.5			2.6			7.0
Realized (loss) gain on mark-to-market derivative contracts⁽¹⁾		(6.4	)		65.2			(29.9	)		328.0
Legal recovery and other		—			(23.5	)		(16.5	)		(110.8	)
Current income taxes attributable to derivative contracts		—			11.3			—			45.1

Operating cash flow (non-GAAP)	$	253.6		$	295.7		$	976.7		$	942.5


Reconciliation of non-GAAP to GAAP measure
Operating cash flow (non-GAAP)	$	253.6		$	295.7		$	976.7		$	942.5
Legal recovery and other		—			23.5			16.5			110.8
Changes in assets and liabilities from operating activities		(24.7	)		(53.5	)		(110.6	)		(181.2	)
Realized loss (gain) on mark-to-market derivative contracts⁽¹⁾		6.4			(65.2	)		29.9			(328.0	)
Current income taxes attributable to derivative contracts		—			(11.3	)		—			(45.1	)

Net cash provided by operating activities (GAAP)	$	235.3		$	189.2		$	912.5		$	499.0

⁽¹⁾	The 2009 realized gain excludes all cash settlements for the $106 crude oil puts and the $54 crude oil swaps monetized in the first quarter of 2009. Cash receipts on these instruments were $121.4 million prior to the $1.1 billion monetization in the first quarter 2009.

Page 13

Plains Exploration & Production Company

Derivative Settlements

(in thousands of dollars)

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


	Three Months Ended December 31,						Twelve Months Ended December 31,
	2010			2009			2010			2009
Oil sales⁽¹⁾	$	(17,854	)	$	(9,198	)	$	(70,834	)	$	2,923
Gas sales		11,285			74,275			37,996			308,146

	$	(6,569	)	$	65,077		$	(32,838	)	$	311,069



				2010			2009
Amortization of monetized derivatives⁽²⁾
First Quarter				$	123,730		$	57,211
Second Quarter					125,105			167,943
Third Quarter					126,479			169,788
Fourth Quarter					126,479			169,788

				$	501,793		$	564,730

⁽¹⁾	Excludes all cash settlements for the $106 crude oil puts and the $54 crude oil swaps monetized in the first quarter of 2009. Cash receipts on these instruments were $121.4 million prior to the $1.1 billion monetization in the first quarter 2009.

⁽²⁾	Represents the net receipts for derivatives monetized in the first quarter of 2009 attributable to their production periods, net of accrued interest on our deferred premiums.

Page 14

Plains Exploration & Production Company

Proved Reserves, Reserve Replacement Ratio, Costs Incurred & Finding and Development Costs


Proved Reserves (MMBOE):
2009 Year-end estimated proved reserves		359.5
2010 Extensions and discoveries		77.1
2010 Revisions		20.0
2010 Acquisitions		1.4
2010 Divestments		(9.3	)
2010 Production		(32.6	)

2010 Year-end estimated proved reserves		416.1


Reserve Replacement Ratio⁽¹⁾⁽²⁾		302	%

Calculation: Reserve extensions, discoveries and other additions, revisions and acquisitions divided by production

Costs Incurred ($ Millions):
Property acquisition costs:
Unproved properties	$	612.5
Proved properties		48.1
Exploration costs		719.0
Development costs		363.2

Total costs incurred⁽³⁾	$	1,742.8


Finding and Development Costs (F&D)⁽²⁾⁽⁴⁾

All-In F&D Costs per BOE	$	17.69
Calculation: Total costs incurred divided by reserve extensions, discoveries, revisions and acquisitions

F&D Costs Excluding Acquisition Costs per BOE	$	11.15
Calculation: Total costs incurred minus unproved and proved property acquisition costs divided by reserve extensions, discoveries and revisions

⁽¹⁾

The Reserve Replacement Ratio is an indicator of our ability to replace annual production volume and grow our reserves. It is important to economically find and develop new reserves that will offset produced volumes and provide for future production given the inherent decline of hydrocarbon reserves as they are produced.

⁽²⁾

The Reserve Replacement Ratio and Finding and Development Costs per BOE are statistical indicators that have limitations, including their predictive and comparative value. As such, these metrics should not be considered in isolation or as a substitute for an analysis of our performance as reported under GAAP. Furthermore, these metrics may not be comparable to similarly titled measurements used by other companies.

⁽³⁾	Includes capitalized interest expense of $128.0 million and capitalized general and administrative expense of $68.0 million.

⁽⁴⁾	Finding and Development Costs per BOE is a non-GAAP metric commonly used in the exploration and production industry. The calculations presented are described above. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

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Plains Exploration & Production Company

700 Milam, Suite 3100, Houston, TX 77002

www.pxp.com