PXP Announces 2010 Fourth-Quarter & Full-Year Results

HOUSTON, Feb. 24, 2011 /PRNewswire/ -- Plains Exploration & Production Company (NYSE: PXP) ("PXP" or the "Company") announces 2010 fourth-quarter and full-year financial and operating 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%.

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 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.

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.

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.


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

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.

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.

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

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

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)

(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.

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.

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.

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		Twelve Months Ended
		December 31,		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.

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.