Plains Exploration & Production 8-K PXP Announces Third Quarter 2004 Results

EXHIBIT 99.1

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

NEWS RELEASE

Contact: Scott D. Winters Director—Investor Relations (832) 239-6190 or (800) 934-6083

FOR IMMEDIATE RELEASE

PXP ANNOUNCES THIRD QUARTER 2004 RESULTS

AND APPROVAL OF 2005 CAPITAL PLAN

Houston, Texas—November 4, 2004—Plains Exploration & Production Company (NYSE: PXP) (“PXP” or the “Company”) today reported third quarter 2004 oil production of 56.9 thousand barrels per day compared to third quarter 2003 production of 26.5 thousand barrels per day and third quarter 2004 gas production of 118.1 million cubic feet per day compared to 79.9 million cubic feet per day in 2003. On a barrel equivalent basis PXP produced an average of 76.5 thousand barrels per day in 2004 compared to 39.8 thousand per day in 2003. Production in the third quarter of 2004 was reduced by approximately 1,000 equivalent barrels per day due to downtime in the Gulf of Mexico caused by Hurricane Ivan. Operations have been fully restored.

PXP reported a net loss of $48.0 million, or a 62 cent loss per diluted share, for the third quarter 2004, compared to net income of $17.5 million, or 43 cents per diluted share, for the third quarter of 2003. As previously disclosed, the third quarter 2004 results include an unrealized after-tax loss on mark-to-market derivative contracts of $71 million, or 91 cents per diluted share, as well as an after-tax $9 million, or 12 cents per diluted share, charge attributable to outstanding stock appreciation rights (“SARs”). In 2003 the third quarter results include an unrealized after-tax gain on mark-to-market derivative contracts of $944 thousand, or 2 cents per diluted share, as well as an after-tax $2.5 million, or 6 cents per diluted share, charge attributable to SARs.

Net cash provided by operating activities was $131.3 million compared to 2003 third quarter operating cash flow of $45.3 million. Net cash provided by operating activities in the third quarter of 2004 includes the reclassification of $41.5 million of derivative settlements which are reported under Cash Flows from Financing Activities.

Long term debt was reduced by $90 million during the quarter with the proceeds of selling our Congo assets and from cash flow.

“PXP made great progress in the third quarter toward positioning the Company for future growth and financial success,” said James C. Flores, PXP’s Chairman, President and Chief Executive

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Officer. “Against the backdrop of strengthening commodity prices we enjoyed operational success at Deep Inglewood, Point Arquello and San Joaquin Valley, all of which should lead to cost efficient production growth in 2005 and beyond. The hedge restructure, while resulting in a loss for accounting purposes in the quarter, will enable us to enjoy higher realized prices in the future. We reduced debt by a meaningful amount in the quarter and expect further reductions by year-end, and as a result of the recently approved $325 million dollar capital budget we expect production in 2005 to be approximately 10% greater than average production in the second half of 2004.”

Operationally, PXP drilled and completed 50 wells during the third quarter. The Western Business Unit accounted for about 50% of the activity, the Central Business Unit about 40% and the Eastern Business Unit the balance. In Deep Inglewood, PXP drilled 4 wells and recently spud DI #13. In early October PXP successfully completed the initial development well into the Rocky Point Field. Drilling operations are underway on the second Rocky Point development well, the Hidalgo C-13 with results expected by year-end 2004.

For the first nine months of 2004, the Company reported oil production of 40.8 thousand barrels per day compared to 25.3 thousand barrels per day in 2003 and gas production of 101.2 million cubic feet per day compared to 39.7 million cubic feet per day in 2003. PXP reported a $18.7 million net loss for the first nine months of 2004, or a 32 cent loss per diluted share, compared with net income of $47.4 million, or $1.51 per diluted share, for the same 2003 period.

Net cash provided by operating activities was $250.2 million for the first three quarters of 2004, compared with $87.9 million for the 2003 period. Net cash provided by operating activities for the first three quarters of 2004 includes the reclassification of $61.3 million of derivative settlements which are reported under Cash Flows from Financing Activities.

Oil and gas capital expenditures for the third quarter 2004 were $63.7 million and for the nine month period capital expenditures were $142.1 million.

Hedging Update

As disclosed on September 21, 2004, during the third quarter of this year PXP restructured a significant portion of its 2005 fixed price oil swaps into collars for the period 2005-2008. The purpose of the transactions was to increase our exposure to higher oil prices in 2005 and provide commodity price downside protection for several years. Specifically, PXP exchanged existing 2005 oil price swaps with respect to 22,000 barrels of oil per day at an average price of $24.25 for new oil price collars relating to 22,000 barrels of oil per day during the period 2005 through 2008 that have a floor price of $25.00 and an average ceiling price of $34.76. The Company’s only remaining 2005 crude oil swaps involve 13,000 barrels of oil per day in the first quarter and 10,000 barrels of oil per day in the second quarter, at fixed prices averaging $25.82 and $25.80, respectively.

The new collars, as well as certain other existing commodity derivative contracts to which we are a party, do not qualify for hedge accounting. Consequently, these contracts are marked-to-market each quarter with changes in market value recognized currently as a derivative gain or loss on the

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income statement. Cash flow is only impacted to the extent the actual settlements under these contracts result in making or receiving a payment from the counterparty and is recognized in financing activities on the cash flow statement.

The market values of these derivative contracts are affected by, among other factors, changes in the underlying commodity prices, commodity price volatility and duration of the contracts. As a general matter, derivative fair value losses are recorded on the income statement when the market value of the underlying commodity increases from period to period and derivative fair value gains are recorded on the income statement when the market value of the underlying commodity decreases from period to period.

2005 Capital Budget

PXP’s Board of Directors has approved a $325 million capital budget for 2005. Approximately 40 – 45% of the budget is expected to be spent on California onshore projects and 10 – 15% is expected to be spent offshore California. Approximately 25 – 30% is expected to be spent in the Eastern Business Unit and includes expected participation in new prospect areas in the Gulf of Mexico. The remainder of the budget is expected to be spent in the Central Business Unit.

Approximately 85% of the budget is allocated toward reserve exploitation, development drilling and maintenance while 15% is allocated for exploration activities.

The 2005 capital plan supports roughly 280 wells which represents an 81% increase over 2004. Approximately 200 wells are planned in California, primarily in the Inglewood Field and in the San Joaquin Valley, 60 in Texas and 20 onshore and offshore Louisiana. In California, development drilling at the offshore Rocky Point project will continue with three to four wells planned. Approximately 30 wells are planned for the Inglewood Deep project, while in San Joaquin Valley drilling activity is expected to more than double to nearly 150 wells. In Texas, activity will focus on low risk projects in the East Texas Cotton Valley and in West Texas at the Pakenham field. Activity in Breton Sound will account for the bulk of the drilling activity offshore Louisiana.

2005 Outlook

PXP affirms the guidance for 2005 originally issued via Form 8-K on October 4, 2004.

The Company will host a conference call to provide an operational update and discuss the quarterly results and other forward-looking items at 2:00 p.m. Central on Thursday, November 4, 2004. Investors wishing to participate may dial 1-877-692-2588 or international: 1-973-582-2745. The replay will be available through 11/18/04 and can be accessed by dialing 1-877-519-4471 or international: 1-973-341-3080, Replay ID: 5315917.

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, East Texas and the Gulf Coast region of the United States. PXP is headquartered in Houston, Texas.

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ADDITIONAL INFORMATION & FORWARD LOOKING STATEMENTS

This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements include those concerning PXP’s strategic plans, expectations and objectives for future operations. 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:

• commodity prices,

• successful sale of assets,

• reliability of reserve and production estimates,

• production expense estimates,

• cash flow estimates,

• future financial performance, and

• other matters that are discussed in PXP’s filings with the SEC.

These statements are based on certain assumptions PXP made based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate under the circumstances. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond PXP’s control. Statements regarding future production are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to, inflation or lack of availability of goods and services, environmental risks, drilling risks and regulatory changes. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. Please refer to our filings with the SEC, including our Forms 10-K and 10-K/A for the year ended December 31, 2003, for a further discussion of these risks.

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Plains Exploration & Production Company

Consolidated Statements of Operations

(amounts in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004 (1)			2003 (2)			2004 (1)			2003 (2)
Revenues
Oil sales	$	148,667		$	52,674		$	297,502		$	147,635
Gas sales		60,827			42,448			156,989			62,676
Other operating revenues		867			260			1,601			667
		210,361			95,382			456,092			210,978
Costs and Expenses
Production costs
Lease operating expenses		44,501			18,606			92,066			49,168
Steam gas costs		14,309			686			22,620			2,147
Electricity		9,207			5,307			21,720			15,635
Production and ad valorem taxes		6,565			3,893			15,118			6,749
Gathering and transportation expenses		2,581			969			5,567			1,296
General and administrative
G&A excluding items below		12,073			5,517			30,916			14,274
Stock appreciation rights		15,023			4,670			28,449			7,317
Merger related costs		2,430			2,007			3,475			3,104
Depletion, depreciation, amortization and accretion		45,807			16,201			94,242			35,327
		152,496			57,856			314,173			135,017
Income from Operations		57,865			37,526			141,919			75,961
Other Income (Expense)
Gain (loss) on mark-to-market derivative contracts (3)		(124,651	)		1,741			(125,842	)		3,207
Loss on debt extinguishment		—			(224	)		(19,691	)		(224	)
Interest expense		(10,969	)		(6,936	)		(26,506	)		(17,130	)
Interest and other income		364			234			669			67
Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change		(77,391	)		32,341			(29,451	)		61,881
Income tax (expense) benefit
Current		(463	)		(271	)		(607	)		(2,700	)
Deferred		29,876			(14,526	)		11,371			(24,134	)
Income (Loss) Before Cumulative Effect of Accounting Change		(47,978	)		17,544			(18,687	)		35,047
Cumulative effect of accounting change, net of tax		—			—			—			12,324
Net Income (Loss)	$	(47,978	)	$	17,544		$	(18,687	)	$	47,371
Earnings (Loss) per Share
Basic
Income (loss) before cumulative effect of accounting change	$	(0.62	)	$	0.44		$	(0.32	)	$	1.13
Cumulative effect of accounting change		—			—			—			0.40
Net income (loss)	$	(0.62	)	$	0.44		$	(0.32	)	$	1.53
Diluted
Income (loss) before cumulative effect of accounting change	$	(0.62	)	$	0.43		$	(0.32	)	$	1.12
Cumulative effect of accounting change		—			—			—			0.39
Net income (loss)	$	(0.62	)	$	0.43		$	(0.32	)	$	1.51
Weighted Average Shares Outstanding
Basic		76,977			40,106			59,008			31,029
Diluted		76,977			40,726			59,008			31,415

(1) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004.

(2) Reflects the acquisition of 3TEC Energy effective June 1, 2003.

(3) Amounts in 2004 consist of unrealized mark-to-market losses of $113.9 million and $109.5 million for the three and nine months ended September 30, 2004, respectively, and cash settlements of $10.8 million and $16.3 million for the same periods. Amounts in 2003 consist of unrealized mark-to-market gains of $1.7 million and $3.2 million for the three and nine months ended September 30, 2003, respectively.

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Plains Exploration & Production Company

Operating Data

	Three Months Ended September 30,						Nine Months Ended September 30,
	2004 (1)			2003 (2)			2004 (1)			2003 (2)
Total Period Production
Oil and Liquids (MBbls)		5,232			2,437			11,174			6,905
Gas (MMcf)		10,863			7,354			27,731			10,828
MBOE		7,043			3,663			15,796			8,710
Average Daily Production
Oil and Liquids (Bbls)		56,870			26,489			40,781			25,293
Gas (Mcf)		118,076			79,935			101,208			39,663
BOE		76,549			39,812			57,650			31,904
Unit Economics (in dollars)
Average Oil & Liquids Sales Price ($/Bbl)
Net realized price before hedging	$	36.64		$	26.37		$	34.20		$	26.87
Hedging revenue (expense) (3)		(8.23	)		(4.76	)		(7.58	)		(5.49	)
Net realized price	$	28.41		$	21.61		$	26.62		$	21.38
Average Gas Sales Price ($/Mcf)
Net realized price before hedging	$	5.71		$	5.03		$	5.74		$	5.29
Hedging revenue (expense) (4)		(0.11	)		0.74			(0.08	)		0.50
Net realized price	$	5.60		$	5.77		$	5.66		$	5.79
Average realized price per BOE	$	29.74		$	25.97		$	28.77		$	24.15
Production expenses per BOE
Lease operating expenses		6.32			5.08			5.83			5.64
Steam gas costs		2.03			0.19			1.43			0.25
Electricity		1.31			1.45			1.38			1.80
Production and ad valorem taxes		0.93			1.06			0.96			0.77
Gathering and transportation expenses		0.37			0.26			0.35			0.15
G&A per BOE
G&A excluding items below		1.71			1.51			1.96			1.64
Stock appreciation rights		2.13			1.27			1.80			0.84
Merger related costs		0.35			0.55			0.22			0.36

(1) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004.

(2) Reflects the acquisition of 3TEC Energy effective June 1, 2003.

(3) Does not include $4.58 per barrel and $3.41 per barrel of cash settlement payments for the three and nine months ended September 30, 2004, respectively, for hedges assumed in connection with the Nuevo and 3TEC mergers. Realized gains and losses on derivative instruments that are designated as a hedge and qualify for hedge accounting are generally included in oil and gas revenues in the period the hedged volumes are sold. However, in the case of the derivatives acquired in connection with our acquisitions of Nuevo and 3TEC, only cash settlements for changes in the fair value subsequent to the acquisition date for the derivative positions assumed will be reflected in our oil and gas revenues. Cash settlements for the liability existing at the merger date are reflected as the payment of a liability.

(4) Does not include $0.25 per Mcf and $0.79 per Mcf of cash settlement payments for the three months ended September 30, 2004 and 2003, respectively or $0.28 per Mcf and $0.67 per Mcf of cash settlement payments for the nine months ended September 30, 2004 and 2003, respectively, for hedges assumed in connection with the Nuevo and 3TEC mergers.

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PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS (Unaudited)

(in thousands of dollars)

	September 30, 2004			December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	1,790		$	1,377
Accounts receivable—Plains All American Pipeline, L.P.		27,747			25,344
Other accounts receivable		91,777			25,267
Inventories		6,831			5,318
Deferred income taxes		90,718			21,807
Assets held for sale		43,612			—
Other current assets		9,615			3,019
		272,090			82,132
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,420,467			1,074,302
Not subject to amortization		180,356			63,658
Other property and equipment		10,253			4,939
		2,611,076			1,142,899
Less allowance for depreciation, depletion and amortization		(272,972	)		(186,004	)
		2,338,104			956,895
Goodwill		221,499			147,251
Other Assets		30,087			19,641
	$	2,861,780		$	1,205,919
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	89,528		$	41,736
Commodity derivative contracts		274,749			55,123
Royalties payable		41,456			19,080
Stock appreciation rights		32,711			16,049
Interest payable		11,189			622
Deposit on assets held for sale		40,711			—
Other current liabilities		30,917			22,476
		521,261			155,086
Long-Term Debt
8.75% Senior Subordinated Notes		276,773			276,906
7.125% Senior Notes		248,718			—
Revolving credit facility		263,000			211,000
		788,491			487,906
Other Long-Term Liabilities
Asset retirement obligation		163,144			33,235
Commodity derivative contracts		234,312			23,697
Deferred income taxes		355,164			143,242
Other long-term liabilities		7,962			8,497
		760,582			208,671
Stockholders’ Equity
Common stock		772			403
Additional paid-in capital		910,281			322,856
Retained earnings		52,879			71,566
Accumulated other comprehensive income		(172,091	)		(40,439	)
Treasury stock		(395	)		(130	)
		791,446			354,256
	$	2,861,780		$	1,205,919

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Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(thousands of dollars)

	Quarter Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(47,978	)	$	17,544		$	(18,687	)	$	47,371
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		45,807			16,201			94,242			35,327
Deferred income taxes		(29,876	)		14,526			(11,371	)		24,134
Debt extinguishment costs		—			—			(4,453	)
Cumulative effect of adoption of accounting change		—			—			—			(12,324	)
Commodity derivative contracts
Unrealized loss (gain) on mark-to-market derivative contracts		113,911			(1,741	)		109,510			(3,207	)
Amortization of derivative liability		(24,738	)		(5,616	)		(43,304	)		(7,050	)
Reclassify financing derivative settlements		41,512			—			61,274			—
Noncash compensation
Stock appreciation rights		14,311			4,025			17,884			5,830
Other noncash compensation		2,289			2,031			6,736			2,069
Other noncash items		(13	)		(25	)		(92	)		352
Changes in assets and liabilities from operating activities		16,071			(1,646	)		38,430			(4,555	)
Net cash provided by operating activities		131,296			45,299			250,169			87,947
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration, development and other costs		(63,683	)		(48,244	)		(142,099	)		(95,024	)
Acquisition of Nuevo Energy Company		(412	)		—			(14,156	)
Acquisition of 3TEC Energy Corporation		—			(580	)		—			(267,197	)
Proceeds from property sales		58,048			8,517			85,892			8,517
Other		(537	)		(1,019	)		(5,739	)		(1,759	)
Net cash provided by (used in) investing activities		(6,584	)		(41,326	)		(76,102	)		(355,463	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facilities		(90,000	)		(6,800	)		52,000			190,400
Proceeds from debt issuance		—			—			248,695			80,061
Retirement of debt assumed in acquisition of Nuevo Energy Company		—			—			(405,000	)		—
Debt issuance costs		(1,189	)		(74	)		(8,988	)		(4,143	)
Derivative settlement		(41,512	)		—			(61,274	)		—
Other		1,096			(561	)		913			174
Net cash provided by (used in) financing activities		(131,605	)		(7,435	)		(173,654	)		266,492
Net increase (decrease) in cash and cash equivalents		(6,893	)		(3,462	)		413			(1,024	)
Cash and cash equivalents, beginning of period		8,683			3,466			1,377			1,028
Cash and cash equivalents, end of period	$	1,790		$	4		$	1,790		$	4

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