Exhibit 99.1

Plains Exploration & Production Company 700 Milam, Suite 3100 Houston, TX 77002

NEWS RELEASE

Contact: Scott D. Winters Director - Investor Relations 713-579-6190 or 800-934-6083

FOR IMMEDIATE RELEASE

PXP ANNOUNCES FIRST QUARTER 2005 RESULTS

Houston, Texas – May 5, 2005 – Plains Exploration & Production Company (NYSE: PXP) (“PXP” or the “Company”) today reported first quarter 2005 production of 66.3 thousand barrels of oil equivalent per day (BOEPD) compared to first quarter 2004 production of 37.7 thousand BOEPD. Oil production represented approximately 74 percent and 64 percent, respectively, of total production in the first quarters of 2005 and 2004.

Due primarily to a previously disclosed charge for derivative fair value losses, PXP reported a net loss of $205.6 million, or $2.66 per share for the first quarter of 2005. In the first quarter PXP recognized a pre-tax loss on mark-to-market derivative contracts of approximately $374 million ($223 million after tax) consisting of realized cash losses of approximately $37 million ($22 million after tax) and an unrealized mark-to-market loss of approximately $337 million ($201 million after tax). In addition, PXP recorded non-cash charges to revenue of $15.2 million ($9.1 million after tax) related to certain oil and gas hedges. First quarter results also include pre-tax charges related to stock-based compensation of $25.8 million ($15.4 million after tax).

“The year to date has been eventful for PXP as we announced several important transactions, including the acquisition of oil and gas properties in the Los Angeles Basin and adjacent Ventura County in California, the sale of our East Texas properties and a major improvement to our hedge positions. Reported earnings for the quarter were negatively impacted by the effect of increasing oil prices on our fixed price derivative contracts that have been limiting our exposure to strong commodity markets. We believe that by eliminating those contracts for 2006 and putting in place $45 put options for 2006 and 2007, PXP is in a position to enjoy much stronger earnings and cash flow as we grow production over the next few years,” commented James C. Flores, PXP’s Chairman, President and Chief Executive Officer.

Total lease operating, steam gas and electricity expense was $9.32 per barrel in the first quarter of 2005, compared to $7.49 per barrel in 2004. The increase is attributable to steam gas costs for the San Joaquin Valley production acquired through the Nuevo merger, partially offset by lower per unit electricity costs. Total per unit production costs in the first quarter of 2005 slightly exceeded the guidance range because of high gas prices affecting steam gas costs and unplanned

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work-over activity on our offshore California properties. General and administrative costs for the quarter, excluding stock based compensation, were $11.7 million. G&A expenses increased from $7.0 million for the first quarter of 2004 primarily due to the acquisition of Nuevo that was completed in the second quarter of 2004 and costs associated with compliance with the Sarbanes-Oxley Act.

Oil and gas capital expenditures for the first quarter of 2005 were $89.3 million compared to $32.2 million for the prior year period.

Operational Update

In the deep area of the Inglewood Field, PXP has drilled a total of 23 wells as of the end of April 2005 with 20 of those wells completed and on line. Also at that time 3 wells were being completed and an additional 2 were drilling. Deep Inglewood production in the first quarter of 2005 increased by about 300 net BOEPD from production rates in the fourth quarter of 2004. First quarter 2005 Deep Inglewood production was also hampered by a temporary gas sales interruption that resulted in a volume loss of approximately 140 BOEPD for the quarter. In the shallow Vickers-Rindge area of the Inglewood Field, PXP has drilled 8 wells in 2005. Six are production wells and 2 are injection wells. Completion operations are currently underway with 2 of the injection wells completed and on line and one production well completed and on line.

At PXP’s Rocky Point development program offshore California, two wells are currently producing and a third well has reached total depth and is being completed. PXP’s working interest in the three wells is 52.6 percent.

In the San Joaquin Valley, PXP has drilled 52 new wells to date in 2005 consisting of 36 steam stimulation producer wells in Diatomite reservoirs in the Cymric Field, 5 steam injectors in the Tulare reservoirs in the Cymric Field, 3 horizontal primary production wells in the South Belridge Diatomite reservoir, 3 steam injectors in the Midway Sunset Field and 5 primary recovery vertical or horizontal wells in the Mount Poso Field. We expect meaningful production increases from the Cymric wells beginning this month and building over the next several months by about 3,000 net BOEPD from the commencement of steaming operations as the drilling program concludes. PXP’s working interest is 100 percent in the above mentioned onshore California wells.

The sale of PXP’s East Texas properties is scheduled to close in May 2005. On March 31, 2005, PXP entered into a purchase and sale agreement with XTO Energy, Inc. to sell 275 net active wells for $350 million. Following customary closing adjustments, PXP expects to receive net cash proceeds of approximately $330 million.

Elimination of 2006 Swap & Collar Positions

As disclosed in our Form 8-K filed on April 15, 2005, in March 2005 PXP entered into a series of contracts that will eliminate all of its 2006 oil price swaps and collars in exchange for a tax deductible payment of approximately $292 million ($175 million after tax). As a result of this tax deduction, as well as the existing net operating loss and enhanced oil recovery credit carry-forwards, PXP does not expect to pay any significant federal or state income taxes in 2005.

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PXP expects to make the $292 million payment to eliminate the 2006 swaps and collars in the second or third quarter of 2005 with proceeds to be received from the announced sale of East Texas properties. This payment will reduce derivative liabilities on the Company’s balance sheet.

Acquisition of Floors for 2006 and 2007 Oil Production

In March 2005, PXP acquired $45 NYMEX put options on 40,000 BOEPD in 2006. In late April, PXP acquired additional $45 put options for 10,000 BOEPD for 2006 and 20,000 BOEPD for 2007. PXP has elected not to use hedge accounting for the puts and consequently the puts will be marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. A summary table of PXP’s derivative position is attached.

PXP will host a conference call to discuss the results and other forward-looking items at 1:00 p.m. Central time today. Investors wishing to participate may dial 1-800-370-0740 or international: 1-973-409-9259. The replay will be available through May 19, 2005 and can be accessed by dialing 1-877-519-4471 or international: 1-973-341-3080, Replay ID: 5984310.

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 statements. These include statements regarding:

* the anticipated closing of the announced property sale,

* commodity prices,

* reliability of reserve and production estimates,

* production expense estimates,

* cash flow estimates,

* future financial performance,

* 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 the year ended December 31, 2004, 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

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associated with these statements and our business that are discussed in this report. 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 for any obligation to disclose material information under the Federal securities laws, we do not intend to update these forward-looking statements and information.

PXP is an independent oil and gas company primarily engaged in the upstream activities of acquiring, exploiting, developing and producing oil and gas in its core areas of operation: onshore and offshore California, West Texas and the Gulf Coast region of the United States. PXP is headquartered in Houston, Texas.

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Plains Exploration & Production Company

Consolidated Statements of Income

(amounts in thousands, except per share data)

	Quarter Ended March 31,
	2005			2004
Revenues
Oil sales	$	134,713		$	49,271
Gas sales		54,479			43,454
Other operating revenues		883			236
		190,075			92,961
Costs and Expenses
Production costs
Lease operating expenses		32,328			18,961
Steam gas costs		16,681			957
Electricity		6,575			5,762
Production and ad valorem taxes		7,336			3,973
Gathering and transportation expenses		3,545			1,196
General and administrative
G&A excluding items below		11,727			7,043
Stock appreciation rights		22,972			10,561
Other stock-based compensation		2,829			2,488
Depletion, depreciation, and amortization		43,593			15,840
Accretion expense		1,745			727
		149,331			67,508
Income from Operations		40,744			25,453
Other Income (Expense)
Gain (loss) on mark-to-market derivative contracts (1)		(374,052	)		(1,565	)
Interest expense		(11,403	)		(6,930	)
Interest and other income		292			262
Income (Loss) Before Income Taxes		(344,419	)		17,220
Income tax (expense) benefit
Current		—			(188	)
Deferred		138,801			(6,634	)
Net Income (Loss)	$	(205,618	)	$	10,398
Earnings (Loss) per Share
Basic	$	(2.66	)	$	0.26
Diluted	$	(2.66	)	$	0.26
Weighted Average Shares Outstanding
Basic		77,202			40,247
Diluted		77,202			40,488

(1) Consists of unrealized mark-to-market losses of $337.0 million and $0.6 million for the three months ended March 31, 2005 and 2004, respectively, and realized cash losses of $37.0 million and $1.0 million for the same periods.

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Plains Exploration & Production Company

Operating Data

	Quarter Ended March 31,
	2005			2004
Total Period Production
Oil and Liquids (MBbls)		4,417			2,195
Gas (MMcf)		9,277			7,404
MBOE		5,963			3,429
Average Daily Production
Oil and Liquids (Bbls)		49,082			24,119
Gas (Mcf)		103,075			81,357
BOE		66,261			37,679
Unit Economics (in dollars)
Average Oil Sales Price ($/Bbl)
Net realized price before hedging	$	40.79		$	31.14
Hedging revenue (expense) (1)		(10.29	)		(8.68	)
Net realized price	$	30.50		$	22.46
Average Gas Sales Price ($/Mcf)
Net realized price before hedging	$	5.78		$	5.73
Hedging revenue (expense) (2)		0.09			0.14
Net realized price	$	5.87		$	5.87
Average Realized Price per BOE	$	31.73		$	27.05
Production expenses per BOE
Lease operating expenses	$	5.42		$	5.53
Steam gas costs		2.80			0.28
Electricity		1.10			1.68
Production and ad valorem taxes		1.23			1.16
Gathering and transportation expenses		0.59			0.35

(1) Includes $6.58 per barrel of non-cash hedging expenses related to terminated hedges. Does not include (i) $2.71 per barrel and $0.02 per barrel in 2005 and 2004, respectively, for cash settlement payments for the merger date liability for hedges assumed in connection with the Nuevo and 3TEC acquisitions; and (ii) $8.38 per barrel in 2005 for cash settlement payments attributable to derivatives that are not accounted for as hedges.

(2) Does not include (i) $0.20 per Mcf and $0.47 per Mcf in 2005 and 2004, respectively, of cash settlement payments for the merger date liability for hedges assumed in connection with the Nuevo and 3TEC acquisitions; and (ii) $0.14 per Mcf in 2004 for cash settlement payments attributable to derivatives that are not accounted for as hedges.

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	March 31, 2005			December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,538		$	1,545
Accounts receivable		121,476			122,288
Inventories		9,345			8,505
Deferred income taxes		194,187			76,823
Assets held for sale		44,128			44,222
Other current assets		13,948			4,784
		384,622			258,167
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,494,343			2,402,179
Not subject to amortization		77,725			79,405
Other property and equipment		13,221			12,546
		2,585,289			2,494,130
Less allowance for depreciation, depletion and amortization		(365,964	)		(323,041	)
		2,219,325			2,171,089
Goodwill		169,828			170,467
Other Assets		35,778			33,522
	$	2,809,553		$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	93,519		$	90,469
Commodity derivative contracts		453,494			175,473
Royalties payable		33,580			39,174
Stock appreciation rights		54,502			34,589
Interest payable		11,562			13,070
Deposit on assets held for sale		40,711			40,711
Other current liabilities		24,372			32,909
		711,740			426,395
Long-Term Debt
8.75% Senior Subordinated Notes		276,681			276,727
7.125% Senior Notes		248,764			248,741
Revolving credit facility		143,400			110,000
		668,845			635,468
Other Long-Term Liabilities
Asset retirement obligation		128,775			126,850
Commodity derivative contracts		363,994			244,140
Other		10,511			10,534
		503,280			381,524
Deferred Income Taxes		276,144			319,483
Stockholders’ Equity
Common stock		774			772
Additional paid-in capital		918,050			913,466
Retained earnings (deficit)		(125,270	)		80,406
Accumulated other comprehensive income		(144,010	)		(123,874	)
Treasury stock, at cost		—			(395	)
		649,544			870,375
	$	2,809,553		$	2,633,245

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Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(thousands of dollars)

	Quarter Ended March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(205,618	)	$	10,398
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		45,338			16,567
Deferred income taxes		(138,801	)		6,634
Commodity derivative contracts
Loss (gain) on derivatives		354,510			(2,911	)
Reclassify financing derivative settlements		50,714			—
Noncash compensation
Stock appreciation rights		19,886			6,303
Other noncash compensation		2,829			2,488
Other noncash items		(23	)		(44	)
Changes in operating assets and liabilities		(31,039	)		(9,053	)
Net cash provided by operating activities		97,796			30,382
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration, development and other costs		(80,954	)		(32,105	)
Proceeds from property sales		—			22,732
Other		(675	)		(218	)
Net cash used in investing activities		(81,629	)		(9,591	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facilities		33,400			(20,000	)
Derivative settlements		(50,714	)		—
Other		1,140			(183	)
Net cash used in financing activities		(16,174	)		(20,183	)
Net increase (decrease) in cash and cash equivalents		(7	)		608
Cash and cash equivalents, beginning of period		1,545			1,377
Cash and cash equivalents, end of period	$	1,538		$	1,985

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Plains Exploration & Production Company

Summary of Open Derivative Positions

May 1, 2005

Period	Commodity	Instrument Type	Daily Volumes	Average Price	Index
Sales of Production
Qualified for Hedge Accounting
2005
2nd Qtr	Crude oil	Swap	10,000 /Bbls	$25.80	WTI
2nd Qtr	Natural gas	Swap	9,500 /MMBtu	$4.66	Waha
3rd Qtr	Natural gas	Swap	5,000 /MMBtu	$4.40	Waha
4th Qtr	Natural gas	Swap	5,000 /MMBtu	$4.40	Waha
Not Qualified for Hedge Accounting
2005
				$27.00 Floor-
2nd Qtr	Crude oil	Collar	6,800 /Bbls	$30.40 Ceiling	WTI
				$26.00 Floor-
3rd Qtr	Crude oil	Collar	14,400 /Bbls	$30.03 Ceiling	WTI
				$26.00 Floor-
4th Qtr	Crude oil	Collar	14,000 /Bbls	$29.33 Ceiling	WTI
				$25.00 Floor-
Apr - Dec	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
2006
Jan - Dec	Crude oil	Put options	50,000 /Bbls	$45.00	WTI
2007
				$25.00 Floor-
Jan - Dec	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
Jan - Dec	Crude oil	Put options	20,000 /Bbls	$45.00	WTI
2008
				$25.00 Floor-
Jan - Dec	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
Purchases of Natural Gas
2005
Apr - Dec	Natural gas	Swap	8,000 /MMBtu	$3.85	Socal

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