Exhibit 99.1

NEWS RELEASE

FOR IMMEDIATE RELEASE

PXP ANNOUNCES 2010 SECOND QUARTER

NET INCOME OF $45 MILLION OR 32 CENTS PER SHARE

5% PRODUCTION GROWTH YEAR-OVER-YEAR

10% LOWER PRODUCTION COSTS PER UNIT YEAR-OVER-YEAR

STRONG DRILLING RESULTS IN THE

GRANITE WASH, HAYNESVILLE, CALIFORNIA AND GULF OF MEXICO

GULF OF MEXICO STRATEGIC ALTERNATIVES PROCESS

Houston, Texas, August 5, 2010—Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) announces 2010 second quarter results and updates drilling activities.

FINANCIAL SUMMARY

For the second quarter 2010, revenues of $364.6 million generated $45.4 million of net income, or $0.32 per diluted share, compared to revenues of $278.7 million and net income of $43.6 million, or $0.37 per diluted share, for the second quarter 2009. These results include 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, which exclude the impact of the derivatives monetized in 2009, a non-cash impairment charge related to our Vietnam oil and gas properties in 2010, a legal recovery in 2009 and other items. When considering these items, net income for the second quarter 2010 was $36.9 million, or $0.26 per diluted share, compared to $71.7 million, or $0.60 per diluted share, for the same period in 2009 (a non-GAAP measure).

For the second quarter 2010, net cash provided by operating activities was $252.7 million and operating cash flow was $212.3 million compared to net cash provided by operating activities of $171.0 million and operating cash flow of $224.1 million for the second quarter 2009 (a non-GAAP measure).

Average daily sales volumes for the second quarter 2010 were 85.0 thousand barrels of oil equivalent (BOE) or 5% higher than 80.6 thousand BOE in the second quarter 2009. Oil represented approximately 53% of the second quarter 2010 daily volumes.

---

Page 2

 

Total production costs per BOE were $13.03 in the second quarter 2010 or 10% lower than $14.43 per BOE in the second quarter 2009.

PXP completed its interpretation of seismic and drilling data from its two offshore Vietnam exploratory wells and has decided not to pursue additional exploratory activities in this area. PXP recorded a $59.5 million non-cash pre-tax impairment charge related to these wells and a corresponding tax benefit of $23.0 million in the second quarter 2010.

For the first six months of 2010, revenues of $748.6 million generated $103.9 million of net income, or $0.73 per diluted share, compared to revenues of $507.2 million and net income of $48.8 million, or $0.43 per diluted share, for the same period in 2009. These results include certain items affecting comparability of operating results. Those items consist of realized and unrealized gains and losses on our mark-to-market derivative contracts, which exclude the impact of the derivatives monetized in 2009, a non-cash impairment charge related to our Vietnam oil and gas properties in 2010, a legal recovery in 2009 and other items. When considering these items, net income for the first six months of 2010 was $80.5 million, or $0.57 per diluted share, compared to $81.7 million, or $0.72 per diluted share, for the same period in 2009 (a non-GAAP measure).

For the first six months of 2010, net cash provided by operating activities was $474.4 million and operating cash flow was $438.5 million compared to net cash provided by operating activities of $141.7 million and operating cash flow of $388.8 million for the same period in 2009 (a non-GAAP measure).

Average daily sales volumes for the first six months of 2010 were 85.1 thousand BOE or 5% higher than 80.7 thousand BOE for the six-month period in 2009.

Total production costs per BOE were $13.69 for the first six months of 2010 or 10% lower than $15.15 per BOE for the six-month period in 2009.

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

SENIOR REVOLVING CREDIT AGREEMENT

PXP amended and restated its senior revolving credit agreement. The agreement extends the senior revolving credit facility maturity to August 3, 2015 from November 6, 2012 and increases PXP’s borrowing base from $1.3 billion to $1.6 billion, an increase of 23% and well in excess of the $1.4 billion of commitments at closing. On June 30, 2010, the senior revolving credit facility had no amounts outstanding.

OPERATIONAL UPDATE

 

•

PXP’s average daily sales volumes were 85.0 thousand BOE per day for the second quarter 2010 or 5% higher than second quarter 2009. This result was impacted by the fire and damage of a portion of the gas processing facility at the Madden Field in Fremont County, Wyoming which reduced net production from the field to PXP by approximately 850 BOE per day in the second quarter. Current production at the Madden Field net to PXP is approximately 3,800 BOE per day which is approximately 75% of full capacity. The operator informed us that it expects to return to full capacity by year end upon completion of all repairs.

---

Page 3

 

PXP reaffirms its 2010 full-year operating and financial guidance, but with lower volumes due to the facilities fire at the Madden Field, PXP expects full-year 2010 average daily sales volumes to be at the lower end of the stated guidance of 88 to 92 thousand BOE per day.

 

•

In the Texas Panhandle Granite Wash development, PXP is currently operating 4 rigs drilling horizontal wells and plans to add 1 additional rig by the end of September 2010 to accelerate development of its inventory of over 100 potential locations. The 5 rig program will enable PXP to spud up to 19 horizontal wells in 2010 and 22 projected wells in 2011. So far this year 2 producing wells have been drilled and completed and a third well is waiting on completion.

PXP’s first Granite Wash horizontal producer, the Thomas 903-H well in the Wheeler area, has been completed with an initial production rate of 12.2 million cubic feet (MMcf) per day with 1,373 barrels of condensate per day and an estimated 1,311 barrels of natural gas liquids per day (3,653 BOE net per day).

PXP’s second Granite Wash horizontal producer, the Hanson 40-4H in the Marvin Lake area, has been completed with an initial rate of 15.4 MMcf per day with 746 barrels of condensate per day and an estimated 1,532 barrels of natural gas liquids per day (3,822 BOE net per day). The Hanson well is located approximately ten miles north of the established Granite Wash Horizontal Producing Trend and is a significant extension to the current play.

Completion operations are underway on the third well, the Hanson 29-2H in the Marvin Lake area, with first production expected in August. The Granite Wash development is expected to contribute approximately 30% of PXP’s production growth in the second half of 2010.

 

•

In the Haynesville Shale, second quarter 2010 average daily sales volumes were 106 million cubic feet equivalent (MMcfe) per day net to PXP, an approximate 19% increase over the 89 MMcfe net per day average rate for the first quarter of 2010. With interests in nearly 50 active drilling rigs, production from this asset area is expected to exceed 125 MMcfe net per day in the fourth quarter 2010 and to contribute approximately 60% of PXP’s production growth for the second half of 2010.

 

•

In California, PXP continues to develop its onshore projects. In the first half of 2010, the Company drilled 59 wells in the San Joaquin Valley and 1 well in the Los Angeles Basin. During the second half of 2010, PXP plans to drill up to 40 wells in the San Joaquin Valley and up to 25 wells in the Los Angeles Basin.

In the San Joaquin Valley, PXP drilled 21 Diatomite wells of which 16 are in the Cymric Field and 5 in the Midway-Sunset Field. The Cymric Field Diatomite wells logged on average 245 feet of pay and each of these wells has been completed and placed on steam-enhanced production. The 5 Midway-Sunset Diatomite wells were drilled in May. These wells logged an average of 175 feet of pay, extended the reservoir and were placed on steam-enhanced production in July.

In the San Joaquin Valley, PXP drilled 38 wells in its conventional sand reservoirs of which 28 are in the South Belridge Field. These wells, all of which are in service, included vertical injectors, vertical producers, and horizontal producers to infill and expand PXP’s existing steamflood in the Pleistocene Tulare Sand. PXP drilled 9 wells in the Pleistocene Tulare Sand in the Cymric Field, most of which represent delineation of existing sands as a result of geologic re-mapping efforts. Drilled in May, these wells logged an average pay of 140 feet, expanded the project inventory and began producing in July. PXP drilled 1 producer in the Midway-Sunset Field in May in a primary producing reservoir. This well logged 200 feet of pay as expected and is now producing.

---

Page 4

 

In the Los Angeles Basin, PXP drilled one development well in the Inglewood Field, logging an expected 450 feet of pay. First production is expected during the third quarter. The Vickers-Rindge waterflood zone has significant amounts of bypassed oil pay which PXP is targeting for infill and improved waterflood injection control.

Initial production expectation for each of the wells drilled in 2010 is between 40 and 50 net barrels of oil per day. Early production results have met or exceeded expectations for the wells drilled to date. California onshore development is expected to contribute approximately 10% of PXP’s production growth in the second half of 2010.

 

•

In the Gulf Coast, PXP plugged and abandoned the first well of the Big Mac project in Southeast Texas after testing the initial objectives. The Company is integrating the well log data into its geophysical model to evaluate the additional opportunities in the area.

 

•

In the Gulf of Mexico, second quarter 2010 average daily sales volumes from the Flatrock area were in line with our expectations at 42 MMcfe per day net to PXP (187 MMcfe per day gross). The operator plans to recomplete the #229 and #230 wells in 2010. PXP’s working interest is 30.0%.

 

•

In the Gulf of Mexico shallow water, drilling operations are ongoing at Blackbeard East, Davy Jones #2 and Blueberry Hill, each operated by McMoRan Exploration Co. (NYSE: MMR).

The Blueberry Hill #9 STK1, located on Louisiana State Lease 340, has been drilled to a true vertical depth of 23,630 feet and is an offset to the previously announced discoveries in 2009. Log-while-drilling tools indicate a possible hydrocarbon bearing zone in a high quality sand measuring 105 feet. Wireline logs will be required to fully evaluate this section. The operator will continue to deepen the well. PXP’s working interest is 47.9%.

The Davy Jones offset appraisal well (Davy Jones #2) on South Marsh Island Block 234 is currently drilling below 12,000 feet towards a proposed total depth of 29,950 feet and is expected to test similar sections up-dip to the discovery well, as well as deeper objectives, including potential additional Wilcox and possibly Cretaceous (Tuscaloosa) sections. PXP’s working interest is 27.7%.

The Davy Jones discovery well on South Marsh Island Block 230 was drilled to a total depth of 29,000 feet and, as reported, the operator logged 200 net feet of pay in multiple Eocene/Paleocene (Wilcox) sands in the well. In March 2010, a production liner was set and the well was temporarily abandoned until necessary equipment for the completion is available. Flow testing will be required to confirm the ultimate hydrocarbon flow rates from the well. The operator completed the well design in the second quarter of 2010 and the long-lead equipment needed to complete, test and produce the well is being procured. The completion and flow test are expected to be performed in the third quarter of 2011. PXP’s working interest is 27.7%.

The Blackbeard East exploration well on South Timbalier Block 144 is currently drilling below 18,800 feet towards a proposed total depth of 29,950 feet. The well will target Middle and Lower Miocene objectives seen below 30,000 feet in Blackbeard West, nine miles away, as well as younger Miocene objectives. PXP’s working interest is 31.5%.

The Lafitte exploration well is expected to commence drilling in second half of 2010 and, like Blackbeard East, will target Middle and Lower Miocene objectives. Lafitte is operated by McMoRan and located on Eugene Island Block 223. PXP’s working interest is 31.5%.

---

Page 5

 

Gulf of Mexico shallow water 2010 drilling plans also include Boudin and Hurricane Deep. The Boudin exploratory prospect, operated by McMoRan and located on Eugene Island Block 26, has a proposed total depth of 23,050 feet and will test Miocene objectives. PXP’s working interest is 37.1%. Hurricane Deep, operated by McMoRan and located on the southern flank of the Flatrock structure on South Marsh Island Block 217, has a proposed total depth of 21,750 feet and is targeting the significant Gyro sand encountered in the Hurricane Deep discovery well and deeper potential. PXP’s working interest is 30.0%.

 

•

In the Gulf of Mexico deepwater, the Lucius project continues to move forward. An integrated project team has been assembled with the goal of project sanction by the end of 2010. As previously announced, the Lucius discovery well, located on Keathley Canyon Block 875, encountered more than 200 net feet of oil pay in Pliocene and Miocene age sands. In early 2010, a sidetrack of the discovery well encountered almost 600 net feet of oil pay with additional gas-condensate pay in the same Pliocene and Miocene age sands seen in the discovery well. The recently drilled Lucius #2 well encountered more than 650 net feet of oil pay in three primary targets. Drilling was suspended approximately 2,000 feet from total depth with one additional target yet to test. Anadarko Petroleum Corporation (NYSE: APC) as the operator ceased drilling operations as a result of the Gulf of Mexico deepwater drilling moratorium. PXP’s working interest is 33.33%.

 

•

PXP has studied its Gulf of Mexico (GOM) operations over the past few months and now plans to reduce its GOM exposure and related capital spending while delivering to its shareholders the unrecognized value created by our recent drilling success. PXP’s goals are to secure $1 to $2 billion of value from its GOM assets through third party joint ventures and/or asset sales and to align capital spending with operating cash flow. PXP has engaged Barclays Capital and Jefferies & Company to assist in executing this value recognition strategy over the next few months.

CONFERENCE CALL

PXP will host a conference call today, Thursday, August 5, 2010 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: 87709209. The replay can be accessed by dialing 1-800-642-1687 or 1-706-645-9291. A live webcast of the conference call 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, Louisiana and the Gulf of Mexico. PXP is headquartered in Houston, Texas.

---

Page 6

 

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:

* oil and gas prices,

* results of drilling activities,

* development schedules,

* 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 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.

 

Contact:
Investors:		Media:
Hance Myers, 713.579.6291		Scott Winters, 713.579.6190
hmyers@pxp.com		swinters@pxp.com

---

Page 7

 

Plains Exploration & Production Company

Consolidated Statements of Income (Unaudited)

(amounts in thousands, except per share data)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Revenues
Oil sales		$	276,263			$	219,589			$	552,267			$	376,203
Gas sales			87,678				58,541				195,417				129,805
Other operating revenues			652				551				959				1,185
			364,593				278,681				748,643				507,193
Costs and Expenses
Lease operating expenses			57,536				63,404				120,039				134,288
Steam gas costs			15,357				10,912				35,020				26,469
Electricity			11,115				12,368				21,149				23,310
Production and ad valorem taxes			3,828				10,457				12,275				22,078
Gathering and transportation expenses			12,912				8,671				22,331				15,318
General and administrative			30,301				37,554				67,691				74,647
Depreciation, depletion and amortization			123,810				90,822				246,203				178,936
Impairment of oil and gas properties			59,475				—				59,475				—
Accretion			4,407				3,556				8,818				7,087
Legal recovery			—				(87,272	)			(8,423	)			(87,272	)
Other operating (income) expense			(3,945	)			1,499				(4,514	)			5,956
			314,796				151,971				580,064				400,817
Income from Operations			49,797				126,710				168,579				106,376
Other (Expense) Income
Interest expense			(28,039	)			(15,935	)			(49,092	)			(37,932	)
Debt extinguishment costs			—				(667	)			(728	)			(10,910	)
Gain (loss) on mark-to-market derivative contracts			57,984				(89,717	)			65,840				(1,578	)
Other income			11,235				899				12,541				192
Income Before Income Taxes			90,977				21,290				197,140				56,148
Income tax (expense) benefit
Current			(2,672	)			43,730				(7,410	)			(12,061	)
Deferred			(42,930	)			(21,371	)			(85,827	)			4,760
Net Income		$	45,375			$	43,649			$	103,903			$	48,847
Earnings per Share
Basic		$	0.32			$	0.37			$	0.74			$	0.43
Diluted		$	0.32			$	0.37			$	0.73			$	0.43
Weighted Average Shares Outstanding
Basic			140,560				118,145				140,153				112,979
Diluted			141,557				118,798				141,752				113,541

---

Page 8

 

Plains Exploration & Production Company

Operating Data (Unaudited)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
Daily Average Volumes
Oil and liquids sales (Bbls)			45,395				48,792				45,307				49,092
Gas (Mcf)
Production			242,961				197,500				243,773				196,727
Used as fuel			5,272				6,422				5,292				6,797
Sales			237,689				191,078				238,481				189,930
BOE
Production			85,889				81,710				85,935				81,880
Sales			85,010				80,638				85,053				80,747
Unit Economics (in dollars)
Average NYMEX Prices
Oil		$	78.05			$	59.79			$	78.46			$	51.68
Gas			4.09				3.50				4.67				4.17
Average Realized Sales Price Before Derivative Transactions
Oil (per Bbl)		$	66.87			$	49.44			$	67.34			$	42.33
Gas (per Mcf)			4.05				3.37				4.52				3.77
Per BOE			47.05				37.90				48.57				34.62
Cash Margin per BOE (1)
Oil and gas revenues		$	47.05			$	37.90			$	48.57			$	34.62
Costs and expenses
Lease operating expenses			(7.44	)			(8.64	)			(7.80	)			(9.19	)
Steam gas costs			(1.99	)			(1.49	)			(2.27	)			(1.81	)
Electricity			(1.44	)			(1.69	)			(1.37	)			(1.59	)
Production and ad valorem taxes			(0.49	)			(1.43	)			(0.80	)			(1.51	)
Gathering and transportation			(1.67	)			(1.18	)			(1.45	)			(1.05	)
Oil and gas related DD&A			(15.33	)			(11.49	)			(15.33	)			(11.49	)
Gross margin (GAAP)			18.69				11.98				19.55				7.98
Oil and gas related DD&A			15.33				11.49				15.33				11.49
Realized gains and losses on derivative instruments (2)			(0.84	)			10.80				(1.23	)			11.57
Cash margin (Non-GAAP)		$	33.18			$	34.27			$	33.65			$	31.04
Oil and gas capital expenditures accrued ($ in thousands) (3)		$	284,753			$	452,060			$	508,169			$	802,418

 

(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.

---

Page 9

 

Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measure

 

		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
		Three Months Ended June 30, 2009
		Oil				Gas			BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	49.44			$	3.37		$	37.90
Realized (losses) gains on derivative instruments			(0.94	)			4.80			10.80
Realized cash price including derivative settlements (non-GAAP)		$	48.50			$	8.17		$	48.70
		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
		Six Months Ended June 30, 2009
		Oil				Gas			BOE
		(per Bbl)				(per Mcf)
Average Realized Sales Price
Average realized price before derivative instruments (GAAP) (1)		$	42.33			$	3.77		$	34.62
Realized gains on derivative instruments (2)			2.40				4.30			11.57
Realized cash price including derivative settlements (non-GAAP)		$	44.73			$	8.07		$	46.19

 

(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 10

 

Plains Exploration & Production Company

Consolidated Statements of Cash Flows (Unaudited)

(in thousands of dollars)

 

		Six Months Ended June 30,
		2010				2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	103,903			$	48,847
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion			255,021				186,023
Impairment of oil and gas properties			59,475				—
Deferred income tax expense (benefit)			85,827				(4,760	)
Debt extinguishment costs			728				10,910
(Gain) loss on mark-to-market derivative contracts			(65,840	)			1,578
Noncash compensation			22,955				32,566
Other noncash items			1,672				2,913
Change in assets and liabilities from operating activities			10,691				(136,387	)
Net cash provided by operating activities			474,432				141,690
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to oil and gas properties			(558,386	)			(826,961	)
Acquisition of oil and gas properties (1)			43,923				—
Proceeds from sales of oil and gas properties			7,230				—
Derivative settlements			(16,153	)			1,380,322
Additions to other property and equipment			(4,394	)			(9,360	)
Net cash (used in) provided by investing activities			(527,780	)			544,001
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit facilities			860,455				2,240,090
Repayments of revolving credit facilities			(1,090,455	)			(3,545,090	)
Proceeds from issuance of Senior Notes			300,000				523,099
Costs incurred in connection with financing arrangements			(5,932	)			(12,114	)
Derivative settlements			—				1,392
Issuance of common stock			—				250,874
Other			—				28
Net cash provided by (used in) financing activities			64,068				(541,721	)
Net increase in cash and cash equivalents			10,720				143,970
Cash and cash equivalents, beginning of period			1,859				311,875
Cash and cash equivalents, end of period		$	12,579			$	455,845

 

(1)	The net cash inflow in 2010 is primarily 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.

---

Page 11

 

Plains Exploration & Production Company

Consolidated Balance Sheets

(in thousands of dollars)

 

		June 30, 2010				December 31, 2009
		(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents		$	12,579			$	1,859
Accounts receivable			168,409				258,585
Commodity derivative contracts			23,623				11,952
Inventories			18,824				19,934
Prepaid expenses and other current assets			19,493				14,305
			242,928				306,635
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization			9,787,554				9,044,146
Not subject to amortization			3,045,819				3,279,537
Other property and equipment			130,061				125,667
			12,963,434				12,449,350
Less allowance for depreciation, depletion, amortization and impairment			(5,917,947	)			(5,616,628	)
			7,045,487				6,832,722
Goodwill			535,237				535,237
Commodity Derivative Contracts			40,378				—
Other Assets			58,643				60,137
		$	7,922,673			$	7,734,731
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	196,363			$	248,454
Commodity derivative contracts			29,009				59,176
Royalties and revenues payable			72,813				78,590
Interest payable			48,414				45,743
Deferred income taxes			—				153,473
Other current liabilities			72,205				97,115
			418,804				682,551
Long-Term Debt			2,722,134				2,649,689
Other Long-Term Liabilities
Asset retirement obligation			226,235				214,231
Other			22,944				55,531
			249,179				269,762
Deferred Income Taxes			1,176,780				933,748
Stockholders’ Equity
Common stock			1,439				1,439
Additional paid-in capital			3,400,263				3,381,566
Retained earnings			150,584				51,204
Treasury stock, at cost			(196,510	)			(235,228	)
			3,355,776				3,198,981
		$	7,922,673			$	7,734,731

---

Page 12

 

Plains Exploration & Production Company

Summary of Open Derivative Positions

At July 1, 2010

 

Period (1)

Instrument Type

Daily Volumes

Average Price (2)

Average Deferred Premium

Index

Sales of Crude Oil Production

2010

Jul - Dec

Put options

40,000 Bbls

$55.00 Strike price

$5.00 per Bbl

(3)

WTI

2011

Jan - Dec

Put options  (4)

31,000 Bbls

$80.00 Floor with a $60.00 Limit

$5.023 per Bbl

WTI

Jan - Dec

Three-way collars  (5)

9,000 Bbls

$80.00 Floor with a $60.00 Limit

$1.00 per Bbl

WTI

$110.00 Ceiling

2012

Jan - Dec

Put options (4)

40,000 Bbls

$80.00 Floor with a $60.00 Limit

$6.087 per Bbl

WTI

Sales of Natural Gas Production

2010

Jul - Dec

Three-way collars  (6)

85,000 MMBtu

$6.12 Floor with a $4.64 Limit

$

0.034 per MMBtu

Henry Hub

$8.00 Ceiling

 

(1)	All of our derivative instruments are settled monthly.

(2)	The average strike prices do not reflect the cost to purchase the put options or collars.

(3)	In addition to the deferred premium, an upfront payment of $3.86 per barrel was paid upon entering into these derivative contracts.

(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. If the index price is at or above $80 per barrel, we pay only the option premium.

(5)

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.

(6)

If the index price is less than the $6.12 per MMBtu floor, we receive the difference between the $6.12 per MMBtu floor and the index price up to a maximum of $1.48 per MMBtu less the option premium. We pay the difference between the index price and $8.00 per MMBtu plus the option premium if the index price is greater than the $8.00 per MMBtu ceiling. If the index price is at or above $6.12 per MMBtu but at or below $8.00 per MMBtu, we pay only the option premium.

---

Page 13

 

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, 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 June 30,
		2010				2009
		(millions of dollars)
Net income (GAAP)		$	45.4			$	43.6
Unrealized (gain) loss on mark-to-market derivative contracts			(58.0	)			89.7
Realized (loss) gain on mark-to-market derivative contracts (1)			(6.5	)			79.3
Impairment of oil and gas properties			59.5				—
Legal recovery			—				(87.3	)
Other non-operating income			(8.1	)			—
Adjust income taxes (2)			4.6				(53.6	)
Adjusted net income (non-GAAP)		$	36.9			$	71.7
		Six Months Ended June 30,
		2010				2009
		(millions of dollars)
Net income (GAAP)		$	103.9			$	48.8
Unrealized (gain) loss on mark-to-market derivative contracts			(65.8	)			1.6
Realized (loss) gain on mark-to-market derivative contracts (1) (3)			(18.9	)			169.1
Impairment of oil and gas properties			59.5				—
Legal recovery			(8.4	)			(87.3	)
Other non-operating income			(8.1	)			—
Adjust income taxes (2)			18.3				(50.5	)
Adjusted net income (non-GAAP)		$	80.5			$	81.7

 

(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 53% and 30% for the three months ended June 30, 2010 and 2009, respectively. Tax rates assumed based upon adjusted earnings are 48% and 41% for the six months ended June 30, 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 14

 

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, 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 June 30,								Six Months Ended June 30,
		2010				2009				2010				2009
		(millions of dollars)
Net income		$	45.4			$	43.6			$	103.9			$	48.8
Items not affecting operating cash flows
Depreciation, depletion, amortization and accretion			128.2				94.4				255.0				186.0
Impairment of oil and gas properties			59.5				—				59.5				—
Deferred income tax expense (benefit)			42.9				21.4				85.8				(4.8	)
Debt extinguishment costs			—				0.7				0.7				10.9
Unrealized (gain) loss on mark-to-market derivative contracts			(58.0	)			89.7				(65.8	)			1.6
Noncash compensation			6.1				18.0				23.0				32.6
Other noncash items			0.3				1.1				1.7				2.9
Realized gain on mark-to-market derivative contracts (1)			(6.7	)			86.2				(16.2	)			186.0
Legal recovery and other			(8.1	)			(87.3	)			(16.5	)			(87.3	)
Current income taxes attributable to derivative contracts			2.7				(43.7	)			7.4				12.1
Operating cash flow (non-GAAP)		$	212.3			$	224.1			$	438.5			$	388.8
Reconciliation of non-GAAP to GAAP measure
Operating cash flow (non-GAAP)		$	212.3			$	224.1			$	438.5			$	388.8
Legal recovery and other			8.1				87.3				16.5				87.3
Changes in assets and liabilities from operating activities			28.3				(97.9	)			10.6				(136.3	)
Realized gain on mark-to-market derivative contracts (1)			6.7				(86.2	)			16.2				(186.0	)
Current income taxes attributable to derivative contracts			(2.7	)			43.7				(7.4	)			(12.1	)
Net cash provided by operating activities (GAAP)		$	252.7			$	171.0			$	474.4			$	141.7

 

(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 15

 

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 June  30,								Six Months Ended June 30,
		2010				2009				2010				2009
Oil sales (1)		$	(17,660	)		$	(4,173	)		$	(35,126	)		$	21,319
Gas sales			11,161				83,449				16,250				147,761
		$	(6,499	)		$	79,276			$	(18,876	)		$	169,080
						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.

###