Plains Exploration & Production 8-K PXP Announces Third Quarter 2005 Results

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 THIRD QUARTER 2005 RESULTS

HOUSTON, Texas, November 3, 2005 – Plains Exploration & Production Company (NYSE:PXP) (“PXP” or the “Company”) today reported third quarter 2005 production of 61.5 thousand barrels of oil equivalent per day (BOEPD), in line with production guidance for the third quarter of 2005 of 61.0 to 63.0 thousand BOEPD. Production was lower year-over-year due to the previously announced asset sales in the fourth quarter 2004 and in the second quarter 2005 as well as the shut-in production due to Hurricanes Katrina and Rita.

Due primarily to a previously disclosed mark-to-market charge for derivative fair value losses associated with the rise in oil prices during the third quarter of 2005, PXP reported a net loss of $31.8 million, or $0.41 per share, for the quarter compared to a net loss of $47.9 million, or $0.62 per share, for the third quarter 2004. The results for the third quarter 2005 reflect the following items:

• $141.6 million pre-tax loss on mark-to-market derivative contracts. Cash payments related to the mark-to-market derivative contracts that settled during the quarter totaled $101.4 million;

• $25.3 million pre-tax non cash charge to revenue related to certain oil and gas hedges;

• $40.1 million pre-tax non cash charge related to stock-based compensation; and

• An effective tax rate of 47 percent to reflect a change in the Company’s estimated annual effective tax rate from 36 to 38 percent.

Without the effects of these items, and applying the 38 percent estimated annual effective tax rate, net income for the third quarter would have been $28.3 million, or $0.36 per share. See the end of this release for an explanation and reconciliation of non-GAAP financial measures.

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Operating cash flow, a non-GAAP measure, was $86.2 million in the third quarter of 2005 compared to $59.5 million in the third quarter of 2004.

“The third quarter results were negatively impacted by the hurricanes by lowering production and increasing unit costs but we’ve made good progress on restoring production and expect to have most of our remaining shut-in production back on line by year end,” commented James C. Flores, PXP’s Chairman, President and Chief Executive Officer.

The average realized sales price per barrel of oil equivalent (BOE) before hedging and derivative transactions was $51.03 during the third quarter of 2005 compared to $36.03 in the third quarter of 2004. Cash payments related to hedging and derivative transactions that settled during the quarter were $18.16 per BOE in 2005 compared to $11.59 in 2004.

Total production costs were $12.50 per BOE in the third quarter of 2005, compared to $10.96 per BOE in 2004. The year-over-year increase per unit is primarily attributable to higher steam gas costs, higher than expected lease operating costs due to workover activity and lost volumes associated with shut-in production from Hurricanes Katrina and Rita.

General and administrative costs for the quarter, excluding stock-based compensation, were $12.6 million. As previously announced, the Company recognized pre-tax non cash stock-based compensation costs of $40.1 million in the third quarter related to stock appreciation rights and restricted stock units.

The Company has issued stock appreciation rights (SARs) to employees and accounting for SARs requires that the Company record an expense or a credit for vested or deemed vested SARs depending on whether, during the period, the stock price either rose or fell, respectively. Accordingly, since the stock price increased from $35.53 per share on June 30, 2005 to $42.82 per share on September 30, 2005 the Company recorded a pre-tax charge of approximately $18.2 million in the third quarter for SARs. Cash payments for SARs exercised during the quarter were approximately $4.4 million. In addition, the Company recognized approximately $21.9 million of pre-tax non cash expense related to the vesting of restricted stock and restricted stock units. During the quarter, the Company issued approximately 0.8 million shares of common stock upon the vesting of restricted stock units.

For the first nine months of 2005 PXP reported production of 65.1 thousand BOEPD compared to 57.6 thousand BOEPD for the first nine months of 2004. Operating cash flow, a non-GAAP measure, was $247.9 million in the first nine months of 2005 compared to $150.5 million in the prior year period.

Due primarily to a mark-to-market charge for derivative fair value losses associated with the rise in oil prices during the first nine months, PXP reported a net loss of $284.8 million, or $3.67 per share. During the first nine months, PXP recognized the following items:

• $629.6 million pre-tax loss on mark-to-market derivative contracts. Cash payments related to the mark-to-market derivative contracts that settled during the period totaled $189.3 million;

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• $59.2 million pre-tax non cash charge to revenue related to certain oil and gas hedges; and

• $72.7 million pre-tax non cash charge related to stock-based compensation.

Without the effects of these items, and applying the 38 percent estimated annual effective tax rate, net income for the first nine months of 2005 would have been $74.8 million, or $0.97 per share.

The average realized sales price per BOE before hedging and derivative transactions was $44.08 during the first nine months of 2005 compared to $34.28 in the first nine months of 2004. Cash payments related to hedging and derivative transactions that settled during the first nine months were $13.84 per BOE in 2005 compared to $9.46 in 2004.

Oil and gas capital expenditures for the third quarter were $112.5 million compared to $57.7 million for the prior year period. For the nine months ended September 30, 2005, oil and gas capital expenditures were $315.1 million compared to $146.5 million for the prior year period. These amounts exclude the cost of acquisitions.

Operational Update

At PXP’s Rocky Point development program offshore California, the third extended reach development well has just been brought on to sales after side-track drilling and completion operations. The initial test rate is approximately 2,800 BOEPD. PXP’s income interest is 57.7 percent. This well was re-drilled in a near horizontal trajectory through the reservoir resulting in approximately 3,100 feet of pay zone exposure to the wellbore. The second Rocky Point development well is available for a similar type of sidetrack if warranted based on sustained performance of the initial side-track test.

During 2005 in the San Joaquin Valley (SJV) of California, PXP has drilled 223 wells through the end of October consisting of 74 wells in Midway Sunset Field, 86 wells in Cymric Field, 56 wells in South Belridge Field with the remainder in other SJV fields. The wells are a mix of vertical and horizontal cyclic steam producers and vertical continuous steam injectors. Pay zone targets are both sands and diatomite reservoirs in further development of existing thermal projects as well as expansion into new “cold” reservoir sections. PXP’s working interest in its leases in the Midway Sunset, Cymric, and South Belridge Fields is typically 100 percent.

In PXP’s Deep Inglewood Project in the Los Angeles Basin, PXP has completed a total of 38 wells below the Vickers-Rindge water-flood horizon as of October 31. Included in that total are 24 wells in the Sentous Formation which is typically the deepest productive zone and an additional 14 wells in the Moynier Formation, a new water-flood target. Moynier water injection started in August, 2005. Present Moynier water-flood pattern production is about 300 BOEPD from five completed producers. PXP is continuing to operate three drilling rigs in the Inglewood Field. PXP’s working interest in the Inglewood Field is 100 percent.

In PXP’s Eastern Development Unit, a second discovery in the Queen Bess Isle Field in Jefferson Parish, Louisiana was made in the third quarter. The well is on line to sales at a gross

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rate of 9.9 million cubic feet per day (MMCFD) and 220 barrels of condensate per day. PXP operates the well with an income interest of approximately 56 percent. This is PXP’s second successful Queen Bess well following on the initial Queen Bess discovery made earlier this year. A third Queen Bess Field area prospect is currently drilling. In the greater Breton Sound area of Louisiana, three new drills originally anticipated for the second half of 2005 have been pushed back due to Hurricane Katrina. One is now anticipated to begin later in the fourth quarter and the remaining two are expected to be drilled in the first quarter of 2006. Total production deferred due to the impacts of Hurricanes Katrina and Rita is approximately 280 net MBOE through October 31, 2005. Current PXP net shut-in volume is approximately 1,710 BOEPD, down from 5,400 net BOEPD immediately after Hurricane Katrina.

In the Miocene Trend of the Green Canyon-Walker Ridge portion of the deep water Gulf of Mexico, PXP is currently participating in two exploratory wells. The Pathfinder Prospect operated by Shell is currently waiting on rig repairs due to damage from Hurricane Katrina. The Bigfoot Prospect operated by Chevron is currently drilling. An additional well at the Caesar Prospect operated by Kerr-McGee is expected to start in late 2005 or early 2006.

Third Quarter Earnings Conference Call

PXP will host a conference call to discuss the results and other forward-looking items at 10:00 a.m. Central time today. Investors wishing to participate may dial 1-800-370-0740 or 1-973-409-9259. The replay will be available through November 17, 2005 and can be accessed by dialing 1-877-519-4471 or 1-973-341-3080, Replay ID: 6598366.

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.

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:

• reserve and production estimates,

• oil and gas prices,

• the impact of derivative positions,

• 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.

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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 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.

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Plains Exploration & Production Company

Consolidated Statements of Income

(amounts in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Revenues
Oil sales	$	217,747		$	148,667		$	515,132		$	297,502
Gas sales		44,231			60,827			152,608			156,989
Other operating revenues		641			867			2,262			1,601
		262,619			210,361			670,002			456,092
Costs and Expenses
Production costs
Lease operating expenses		36,284			44,501			105,489			92,066
Steam gas costs		17,932			14,309			51,017			22,620
Electricity		8,917			9,207			23,678			21,720
Production and ad valorem taxes		5,111			6,565			18,414			15,118
Gathering and transportation expenses		2,467			2,581			8,416			5,567
General and administrative
G&A excluding items below		12,638			12,236			35,876			27,746
Stock appreciation rights		18,224			15,023			44,101			28,449
Other stock-based compensation		21,902			2,267			28,657			6,645
Depletion, depreciation, and amortization		40,626			42,820			129,964			88,651
Accretion expense		1,926			2,987			5,605			5,591
		166,027			152,496			451,217			314,173
Income from Operations		96,592			57,865			218,785			141,919
Other Income (Expense)
Gain (loss) on mark-to-market derivative contracts		(141,646	)		(124,651	)		(629,569	)		(125,842	)
Loss on debt extinguishment		—			—			—			(19,691	)
Interest expense		(14,478	)		(10,969	)		(40,039	)		(26,506	)
Interest and other income (expense)		(392	)		364			(220	)		669
Income (Loss) Before Income Taxes		(59,924	)		(77,391	)		(451,043	)		(29,451	)
Income tax (expense) benefit
Current		757			(463	)		(573	)		(607	)
Deferred		27,318			29,876			166,819			11,371
Net Income (Loss)	$	(31,849	)	$	(47,978	)	$	(284,797	)	$	(18,687	)
Earnings (Loss) per Share
Basic	$	(0.41	)	$	(0.62	)	$	(3.67	)	$	(0.32	)
Diluted	$	(0.41	)	$	(0.62	)	$	(3.67	)	$	(0.32	)
Weighted Average Shares Outstanding
Basic		78,053			76,977			77,531			59,008
Diluted		78,053			76,977			77,531			59,008

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Plains Exploration & Production Company

Operating Data

	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Total Period Production
Oil and Liquids (MBbls)		4,635		5,232		13,792		11,174
Gas (MMcf)		6,135		10,863		23,913		27,731
MBOE		5,657		7,043		17,777		15,796
Average Daily Production
Oil and Liquids (Bbls)		50,374		56,870		50,520		40,781
Gas (Mcf)		66,687		118,076		87,593		101,208
BOE		61,487		76,549		65,117		57,650
Unit Economics (in dollars)
Average Prices
NYMEX Oil	$	63.16	$	43.85	$	55.45	$	39.13
Henry Hub gas		8.52		5.99		7.18		5.89
Average Realized Sales Price Before Hedging
Oil (per Bbl)	$	52.53	$	36.64	$	45.69	$	34.20
Gas (per Mcf)		7.37		5.71		6.43		5.74
Per BOE		51.03		36.03		44.08		34.28
Production expenses per BOE
Lease operating expenses	$	6.41	$	6.32	$	5.93	$	5.83
Steam gas costs		3.17		2.03		2.87		1.43
Electricity		1.58		1.31		1.33		1.38
Production and ad valorem taxes		0.90		0.93		1.04		0.96
Gathering and transportation expenses		0.44		0.37		0.47		0.35
Cash payments related to 2005 and 2004 derivative contracts that settled during the periods were as follows ($/millions):
Contracts accounted for using hedge accounting
Oil	$	—	$	67.0	$	53.0	$	122.8
Gas		1.3		3.8		3.7		10.1
Mark-to-market contracts		101.4		10.7		189.3		16.3

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	September 30, 2005			December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	1,306		$	1,545
Accounts receivable		135,333			122,288
Inventories		9,565			8,505
Deferred income taxes		142,597			76,823
Assets held for sale		—			44,222
Other current assets		5,315			4,784
		294,116			258,167
Property and Equipment, at cost
Oil and natural gas properties - full cost method
Subject to amortization		2,513,945			2,402,179
Not subject to amortization		89,101			79,405
Other property and equipment		16,069			12,546
		2,619,115			2,494,130
Less allowance for depreciation, depletion and amortization		(450,562	)		(323,041	)
		2,168,553			2,171,089
Goodwill		172,558			170,467
Other Assets		36,152			33,522
	$	2,671,379		$	2,633,245
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	124,333		$	90,469
Commodity derivative contracts		173,330			175,473
Royalties payable		49,223			39,174
Stock appreciation rights		68,291			34,589
Interest payable		11,481			13,070
Deposit on assets held for sale		—			40,711
Other current liabilities		35,148			32,909
		461,806			426,395
Long-Term Debt
8.75% Senior Subordinated Notes		276,586			276,727
7.125% Senior Notes		248,813			248,741
Revolving credit facility		238,500			110,000
		763,899			635,468
Other Long-Term Liabilities
Asset retirement obligation		144,286			126,850
Commodity derivative contracts		440,774			244,140
Other		7,434			10,534
		592,494			381,524
Deferred Income Taxes		228,405			319,483
Stockholders’ Equity
Common stock		784			772
Additional paid-in capital		931,893			913,466
Retained earnings (deficit)		(204,449	)		80,406
Accumulated other comprehensive income		(103,248	)		(123,874	)
Treasury stock, at cost		(205	)		(395	)
		624,775			870,375
	$	2,671,379		$	2,633,245

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Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(thousands of dollars)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(31,849	)	$	(47,978	)	$	(284,797	)	$	(18,687	)
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		42,552			45,807			135,569			94,242
Deferred income taxes		(27,318	)		(29,876	)		(166,819	)		(11,371	)
Debt extinguishment costs		—			—			—			(4,453	)
Commodity derivative contracts
Loss (gain) on derivatives		66,924			84,777			358,838			66,206
Reclassify financing derivative settlements		94,190			41,512			364,932			61,274
Noncash compensation
Stock appreciation rights		13,829			14,311			30,729			17,884
Other noncash compensation		22,064			(7,564	)		29,078			6,736
Other noncash items		(23	)		(13	)		(69	)		(92	)
Changes in operating assets and liabilities
Commodity derivative contracts		7,590			4,495			(135,348	)		15,635
Other		(13,252	)		25,825			(43,938	)		22,795
Net cash provided by operating activities		174,707			131,296			288,175			250,169
CASH FLOWS FROM INVESTING ACTIVITIES
Exploration, development and other costs		(80,812	)		(63,683	)		(261,576	)		(142,099	)
Acquisition of oil and gas properties		(13,427	)		—			(131,802	)		—
Acquisition of Nuevo, net of cash acquired		—			(412	)		—			(14,156	)
Proceeds from property sales		2,127			58,048			343,096			85,892
Other		(927	)		(537	)		(3,523	)		(5,739	)
Net cash used in investing activities		(93,039	)		(6,584	)		(53,805	)		(76,102	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facilities		12,000			(90,000	)		128,500			52,000
Proceeds from debt issuance		—			—			—			248,695
Retirement of debt assumed in acquisition of Nuevo		—			—			—			(405,000	)
Debt issuance costs		(31	)		(1,189	)		(1,521	)		(8,988	)
Derivative settlements		(94,190	)		(41,512	)		(364,932	)		(61,274	)
Other		890			1,096			3,344			913
Net cash used in financing activities		(81,331	)		(131,605	)		(234,609	)		(173,654	)
Net increase (decrease) in cash and cash equivalents		337			(6,893	)		(239	)		413
Cash and cash equivalents, beginning of period		969			8,683			1,545			1,377
Cash and cash equivalents, end of period	$	1,306		$	1,790		$	1,306		$	1,790

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Plains Exploration & Production Company

Summary of Open Derivative Positions

Period	Commodity	Instrument Type	Daily Volumes	Average Price	Index
Sales of Production
Qualified for Hedge Accounting
2005
4th Qtr	Natural gas	Swap	5,000 /MMBtu	$4.40	Waha
Not Qualified for Hedge Accounting
2005
				$26.00 Floor-
4th Qtr	Crude oil	Collar	14,000 /Bbls	$29.33 Ceiling	WTI
				$25.00 Floor-
4th Qtr	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
2006
Jan - Dec	Crude oil	Put options	50,000 /Bbls	$55.00 Strike price	WTI
2007
				$25.00 Floor-
Jan - Dec	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
Jan - Dec	Crude oil	Put options	50,000 /Bbls	$55.00 Strike price	WTI
2008
				$25.00 Floor-
Jan - Dec	Crude oil	Collar	22,000 /Bbls	$34.76 Ceiling	WTI
Purchases of Natural Gas
Qualified for Hedge Accounting
2005
4th Qtr	Natural gas	Swap	8,000 /MMBtu	$3.85	Socal
Not Qualified for Hedge Accounting
2006
Jan - Dec	Natural gas	Call options	30,000 /MMBtu	$12.00 Strike price	Socal

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Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measures

The following is a reconciliation of net cash provided by operating activities to operating cash flow. Management believes that the non-GAAP measure of operating cash flow is useful information for investors because it is used internally, illustrative of the non-cash impact of the Company’s derivative contracts and accepted by the investment community as a means of measuring the Company’s ability to fund capital expenditures and service debt.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(millions of dollars)
Net cash provided by operating activities (GAAP)	$	174.7		$	131.3		$	288.2		$	250.2
Changes in operating assets and liabilities
Commodity derivative contracts		(7.6	)		(4.5	)		135.3			(15.6	)
Other		13.2			(25.8	)		43.9			(22.8	)
Cash payments for commodity derivative contracts that settled during the period that are reflected as financing cash flows in the statement of cash flows		(94.1	)		(41.5	)		(219.5	)		(61.3	)
Operating cash flow (Non-GAAP)	$	86.2		$	59.5		$	247.9		$	150.5
	2005
	1st Qtr			2nd Qtr			3rd Qtr			9 Months
	(millions of dollars)
Net cash provided by operating activities (GAAP)	$	97.8		$	15.7		$	174.7		$	288.2
Changes in operating assets and liabilities
Commodity derivative contracts		(3.0	)		145.9			(7.6	)		135.3
Other		34.1			(3.4	)		13.2			43.9
Cash payments for commodity derivative contracts that settled during the period that are reflected as financing cash flows in the statement of cash flows		(50.8	)		(74.6	)		(94.1	)		(219.5	)
Operating cash flow (Non-GAAP)	$	78.1		$	83.6		$	86.2		$	247.9

Operating cash flow is calculated by adjusting the GAAP measure of cash provided by operating activities to exclude changes in assets and liabilities and include derivative cash flows that are classified as a financing activity in the statement of cash flows. Pursuant to SFAS 149 “Amendment of SFAS 133, Derivative Instruments and Hedging Activities”, certain of our derivative instruments are deemed to contain a significant financing element and cash flows associated with these positions are required to be reflected as financing activities. The cash flows that were reclassified in the tables above reflect settlements for 2005 and 2004 positions and do not include the $145.4 million that we paid in the second quarter of 2005 to eliminate our 2006 collar positions.

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Plains Exploration & Production Company

Reconciliation of GAAP to Non-GAAP Measures

The following is a reconciliation of net income (loss) to net income (loss) excluding certain items. Management believes that the non-GAAP measure of net income (loss) excluding certain items is useful information for investors because it is used internally and is accepted by the investment community as a means to evaluate the Company’s ongoing results of operations.

	Third Quarter 2005			Nine Months 2005
	(millions of dollars)
Net income (loss)	$	(31.8	)	$	(284.8	)
Loss on mark-to-market derivative contracts		141.6			629.6
Cash payments on mark-to-market derivative contracts		(101.4	)		(189.3	)
Non cash charge to revenue for oil and gas hedges		25.3			59.2
Non cash charge related to stock-based compensation		40.1			72.7
Tax effect of foregoing adjustments at 38%		(40.4	)		(218.9	)
Adjust effective tax rate to 38%		(5.1	)		6.3
Net income (loss) excluding certain items (Non-GAAP)	$	28.3		$	74.8

The cash payments on mark-to-market derivative contracts in the table above reflects settlements for 2005 positions. The amount for the nine months of 2005 does not include the $145.4 million that we paid in the second quarter of 2005 to eliminate our 2006 collar positions.

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