Plains Exploration & Production 8-K PXP Announces 2004 Results, Agreement to Purchase

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 2004 RESULTS, AGREEMENT TO PURCHASE

$119 MILLION OF CALIFORNIA PRODUCING PROPERTIES AND

REVISED 2005 CAPITAL BUDGET

Houston, Texas—March 15, 2005—Plains Exploration & Production Company (NYSE: PXP) (“PXP” or the “Company”) today reported fourth quarter 2004 oil production of 57.2 thousand barrels per day compared to fourth quarter 2003 production of 25.7 thousand barrels per day and fourth quarter 2004 gas production of 118.0 million cubic feet per day compared to 80.1 million cubic feet per day in 2003. On a barrel equivalent basis PXP produced an average of 76.9 thousand barrels per day in the fourth quarter of 2004 compared to 39.0 thousand barrels per day in 2003.

“PXP ended the year with a host of accomplishments,” commented James C. Flores, PXP’s Chairman, President and Chief Executive Officer. “We completed and integrated a major acquisition, brought the Rocky Point Field offshore California on production and commenced an active, multi-year drilling program in the deeper zones of the Inglewood Field in the Los Angeles Basin.”

“We are also confident that 2005 will be another highly successful year as we continue to develop our rich resource base, which is being supplemented with the property acquisition we announced today. These California properties are in our backyard so it did not take our team long to identify over 100 workover and drilling opportunities. Furthermore, the increase in the capital budget will accelerate our growth as we pursue additional opportunities across the Company.”

PXP reported net income of $27.5 million, or 35 cents per diluted share, for the fourth quarter 2004, compared to net income of $12.0 million, or 30 cents per diluted share, for the fourth quarter 2003. As previously disclosed, the fourth quarter 2004 results include an unrealized pre-tax loss on mark-to-market derivative contracts of $8.6 million. In addition, fourth quarter results include pre-tax charges related to stock-based compensation of $8.5 million of which $7.0 million is attributable to outstanding stock appreciation rights (“SARS”) and a $6.8 million pre-tax charge for legal and regulatory matters. Fourth quarter 2003 results include a pre-tax charge related to stock-based compensation of $10.9 million nearly all of which is attributable to SARS.

—MORE—

Page 2

Total per unit production costs in the fourth quarter of 2004 averaged $9.33 per barrel compared to $8.31 per barrel in 2003. 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 fourth quarter of 2004 were in the low end of the guidance range. General and administrative costs exceeded the guidance range because of higher than expected costs to comply with Section 404 of the Sarbanes-Oxley Act. Oil and gas depreciation, depletion and amortization of $6.99 per barrel exceeded the guidance range due to estimated future development costs of reserves added during 2004. PXP’s provision for taxes was lower than expected because of the availability of net operating losses and enhanced oil recovery credits.

Net cash provided by operating activities was $113.1 million compared to 2003 fourth quarter operating cash flow of $30.3 million. Net cash provided by operating activities in the fourth quarter of 2004 includes the reclassification of $42.2 million of derivative settlements which are reported under Cash Flows from Financing Activities.

After reducing long term debt by $153.0 million during the quarter with proceeds from previously announced property sales, PXP’s debt to total capitalization was 42 percent at year-end 2004 compared to 58 percent at year-end 2003.

For the year PXP reported oil production of 44.9 thousand barrels per day compared to 2003 production of 25.4 thousand barrels per day and 2004 gas production of 105.4 million cubic feet per day compared to 49.8 million cubic feet per day in 2003. On a barrel equivalent basis PXP produced an average of 62.5 thousand barrels per day in 2004 compared to 33.7 thousand barrels per day in 2003.

PXP reported net income of $8.8 million, or 14 cents per diluted share, for 2004, compared to net income of $59.4 million, or $1.78 per diluted share, for 2003. The 2004 results include an unrealized pre-tax loss on mark-to-market derivative contracts of $118.1 million. In addition, year-end results include pre-tax charges related to stock-based compensation of $43.6 million of which $35.5 million is attributable to outstanding SARS and a pre-tax $19.7 million loss related to the debt restructuring completed subsequent to the Nuevo acquisition. In aggregate, these charges reduced after-tax net income by $111.9 million. Net income for 2003 includes a $12.3 million credit, related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Assets Retirement Obligations” and a pre-tax charge attributable to SARS of $18.0 million.

Net cash provided by operating activities for the year was $363.2 million compared to 2003 cash flow of $118.3 million. Net cash provided by operating activities for 2004 includes the reclassification of $103.5 million of derivative settlements which are reported under Cash Flows from Financing Activities.

Oil and gas capital expenditures for the fourth quarter 2004 were $69.3 million and for the year capital expenditures were $211.4 million, excluding the cost of acquisitions.

—MORE—

Page 3

As previously reported, year-end 2004 estimated proved reserves totaled 419.3 million barrels of oil equivalent, a 49 percent increase over year-end 2003. PXP replaced 975 percent of the 22.9 million barrels of oil equivalent it produced during 2004 at an average all-source cost of $6.97 per barrel of oil equivalent. Reserve additions through discoveries, extensions and revisions replaced 152 percent of production at an average cost of $5.71 per barrel of oil equivalent. Reserve additions from acquisitions totaled 188.2 million barrels of oil equivalent and sales of reserves totaled 61.7 million barrels of oil equivalent.

Producing Property Purchase

PXP has agreed to acquire oil and gas properties for $119 million from a private company. The properties currently produce approximately 2,000 net equivalent barrels per day and are primarily located in the Los Angeles Basin of onshore California with some smaller properties located in adjacent Ventura County. PXP estimates proved reserves are approximately 17.4 million barrels of oil equivalent with additional unproven resource potential related to field extension, new fault block, or deeper zone possibilities. Production growth over each of the next several years is expected from development and exploitation work. The two largest fields are Las Cienegas located near and geologically similar to PXP’s Inglewood and Inglewood satellite fields and Sansinena located near PXP’s existing Montebello Field. The transaction is expected to close early in the second quarter subject to customary closing conditions. The purchase will be financed under the existing credit facility.

Revised 2005 Capital Budget

PXP’s 2005 capital budget, exclusive of acquisitions, has been increased from $325 million to $375 million. The increase results from additional exploration opportunities in the Gulf Coast and Gulf of Mexico, ramping up of drilling activity onshore California and expected increases in service costs. Exploration spending will increase to approximately 15 percent of total capital for prospects mainly located in Louisiana coastal waters, PXP fee mineral land in south Louisiana, and in the Gulf of Mexico including the deep water portion of the Gulf. In California, additional capital will be employed in the Inglewood Field as well as in the San Joaquin Valley. The addition of a third drilling rig in the Inglewood Field which commenced operations earlier this month will enable the drilling of 40-45 Deep Inglewood wells along with another 10-15 shallow water-flood wells this year. Total 2005 California onshore drilling well count, including Inglewood, will now range from 235-245, up from approximately 200 in the original budget. The capital budget includes estimated capitalized G&A and capitalized interest of $25.0 million.

Operational Update

In the Deep Inglewood area of the Los Angeles Basin, PXP has drilled 20 wells as of the end of February 2005 with 17 of those wells completed and on line producing 2,500 gross barrels of oil equivalent per day. Also at that time 3 wells were being completed and an additional 2 were drilling. All Deep Inglewood wells drilled to date have been successfully completed in at least one of the productive reservoirs with no dry holes. Most wells have additional pay zones available for future completions. PXP’s working interest in both the shallow and deep sections of the Inglewood Field is 100 percent with income interests generally about 80 percent. The Deep

—MORE—

Page 4

Inglewood wells typically produce lighter gravity oil of approximately 27+ degree API with higher gas-oil ratios than the shallow Inglewood wells.

In the San Joaquin Valley, PXP has drilled 22 new wells to date in 2005 consisting of 14 steam stimulation producer wells in Diatomite reservoirs in the Cymric Field, 3 horizontal primary production wells in the South Belridge Diatomite reservoir, and 5 primary recovery vertical or horizontal wells in the Mount Poso Field. Production from the Cymric wells will not begin in appreciable amounts until the drilling program is completed which is forecast to conclude in May. In Cymric steaming operations are curtailed while drilling is ongoing to avoid stream breakthroughs and drilling problems. Completion and testing of the South Belridge and Mount Poso wells is in progress.

PXP suffered no significant damage from recent California rainstorms and mud slide events; however, electrical power failures caused a higher than normal rate of downtime in the first quarter. Additionally, road and location conditions affecting the moving of rig and frac equipment delayed the start of several drilling wells or new well completions. These circumstances have had a negative impact on production volumes in the first quarter of 2005. PXP had no pollution events or accidents related to the recent storms.

PXP’s first 2 Rocky Point wells drilled from the Point Arguello platforms offshore California are producing at a combined rate of approximately 4,500 gross barrels of oil per day. The second Rocky Point well, Hidalgo C-13, was completed in early January 2005 and a third well is drilling. After the completion of the third well, the remaining wells needed to complete the development plan, up to a maximum of 5, will be drilled from the Point Arguello Hermosa Platform after a rig move. PXP’s working interest in all the Rocky Point wells is approximately 52.6 percent with an income interest of about 43.8 percent.

Since PXP’s third quarter announcement on November 4, 2004, the Company has made 3 new discoveries in south Louisiana. In the Gridiron area of the Breton Sound Extension play in Plaquemines Parish, the Saint prospect was completed with an initial test rate of 9.4 million cubic feet per day of natural gas and 96 barrels of condensate per day at 3,500 psi flowing pressure. After installation of facilities, the well began producing to sales in the last few days. PXP’s working interest is 37.5 percent and income interest is approximately 28 percent. In Terrebonne Parish, PXP contributed fee minerals to the South Bourg Prospect which was a discovery with about 40 feet of indicated natural gas pay. Completion operations are in progress with initial production to sales expected by early April. PXP has a cost free 10 percent income interest in the well. In Jefferson Parish the PXP operated Queen Bess Island Prospect is an indicated discovery with about 60 feet of natural gas pay logged. Planning for completion operations and facility installation is in progress with initial sales expected by June. PXP has a 50 percent working interest and approximate 41 percent income interest.

In PXP’s East Texas area consistent drilling operations have continued throughout the fourth quarter of 2004 into 2005 with 3 to 4 rigs operating. Activity at this level or somewhat higher is expected to continue throughout 2005.

—MORE—

Page 5

2005 Outlook

PXP will file an 8-K today that updates the guidance for 2005 that was originally issued via Form 8-K on October 4, 2004.

PXP will host a conference call to discuss the results and other forward-looking items at 10:30 a.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 March 29, 2005 and can be accessed by dialing 1-877-519-4471 or international: 1-973-341-3080, Replay ID: 5770076.

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:

* closing of the announced acquisition,

* 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 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, uncertainties regarding the closing of the announced acquisition, 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.

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.

—MORE—

Page 6

Plains Exploration & Production Company

Consolidated Statements of Income

(amounts in thousands, except per share data)

	Quarter Ended December 31,						Year Ended December 31,
	2004			2003			2004(1)			2003(2)
Revenues
Oil sales	$	150,554		$	50,513		$	448,056		$	198,148
Gas sales		64,371			42,378			221,360			105,054
Other operating revenues		689			221			2,290			888
		215,614			93,112			671,706			304,090
Costs and Expenses
Production costs
Lease operating expenses		30,474			17,690			122,540			66,858
Steam gas costs		17,901			694			40,521			2,841
Electricity		8,417			6,750			30,137			22,385
Production and ad valorem taxes		7,214			3,376			22,332			10,125
Gathering and transportation expenses		1,983			1,314			7,550			2,610
General and administrative
G&A excluding items below		11,123			5,367			35,394			18,694
Stock appreciation rights		7,015			10,693			35,464			18,010
Other stock-based compensation		1,447			243			8,092			1,190
Merger related costs		2,772			2,160			6,247			5,264
Provision for legal and regulatory settlements		6,845			—			6,845			—
Depletion, depreciation, amortization and accretion		53,743			17,157			147,985			52,484
		148,934			65,444			463,107			200,461
Income from Operations		66,680			27,668			208,599			103,629
Other Income (Expense)
Gain (loss) on mark-to-market derivative contracts (3)		(24,472	)		(2,360	)		(150,314	)		847
Loss on debt extinguishment		—			—			(19,691	)		(224	)
Interest expense		(10,788	)		(6,648	)		(37,294	)		(23,778	)
Interest and other income		54			(2	)		723			65
Income Before Income Taxes and Cumulative
Effect of Accounting Change		31,474			18,658			2,023			80,539
Income tax (expense) benefit
Current		232			1,476			(375	)		(1,224	)
Deferred		(4,179	)		(8,094	)		7,192			(32,228	)
Income Before Cumulative Effect of Accounting Change		27,527			12,040			8,840			47,087
Cumulative effect of accounting change, net of tax		—			—	��		—			12,324

Net Income	$	27,527	$	12,040	$	8,840	$	59,411
Earnings per Share
Basic
Income before cumulative effect of accounting change	$	0.36	$	0.30	$	0.14	$	1.41
Cumulative effect of accounting change		—		—		—		0.37
Net income	$	0.36	$	0.30	$	0.14	$	1.78
Diluted
Income before cumulative effect of accounting change	$	0.35	$	0.30	$	0.14	$	1.41
Cumulative effect of accounting change		—		—		—		0.37
Net income	$	0.35	$	0.30	$	0.14	$	1.78
Weighted Average Shares Outstanding
Basic		77,043		40,124		63,542		33,321
Diluted		77,824		40,396		64,014		33,469

(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 $8.6 million and $118.1 million for the three months and year ended December 31, 2004, respectively, and cash settlements of $15.9 million and $32.2 million for the same periods. Amounts in 2003 consist of unrealized mark-to-market losses of $2.4 million for the three months ended December 31, 2003 and unrealized marked-to-market gains of $0.8 million for the year then ended.

—MORE—

Page 7

Plains Exploration & Production Company

Operating Data

	Quarter Ended December 31,		Year Ended December 31,
	2004	2003	2004(1)	2003(2)
Total Period Production
Oil and Liquids (MBbls)	5,267	2,362	16,441	9,267
Gas (MMcf)	10,859	7,367	38,590	18,195
MBOE	7,076	3,590	22,872	12,300
Average Daily Production
Oil and Liquids (Bbls)	57,246	25,674	44,920	25,389
Gas (Mcf)	118,027	80,076	105,436	49,849
BOE	76,917	39,022	62,492	33,699
Unit Economics (in dollars)
Average Oil & Liquids Sales Price ($/Bbl)

Net realized price before hedging	$	40.19		$	27.10		$	36.12		$	26.92
Hedging revenue (expense) (3)		(11.60	)		(5.71	)		(8.87	)		(5.54	)
Net realized price	$	28.59		$	21.39		$	27.25		$	21.38
Average Gas Sales Price ($/Mcf)
Net realized price before hedging	$	6.29		$	4.62		$	5.90		$	5.01
Hedging revenue (expense) (4)		(0.36	)		1.13			(0.16	)		0.76
Net realized price	$	5.93		$	5.75		$	5.74		$	5.77
Average realized price per BOE	$	30.37		$	25.87		$	29.27		$	24.65
Production expenses per BOE
Lease operating expenses		4.31			4.93			5.36			5.44
Steam gas costs		2.53			0.19			1.77			0.23
Electricity		1.19			1.88			1.32			1.82
Production and ad valorem taxes		1.02			0.94			0.98			0.82
Gathering and transportation expenses		0.28			0.37			0.33			0.21
G&A per BOE
G&A excluding items below		1.57			1.49			1.55			1.52
Stock appreciation rights		0.99			2.98			1.55			1.46
Other stock-based compensation		0.20			0.07			0.35			0.10
Merger related costs		0.39			0.60			0.27			0.43

(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 $4.46 per barrel and $3.75 per barrel of cash settlement payments for the three months and year ended December 31, 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 $.32 per Mcf and $.86 per Mcf of cash settlement payments for the three months ended December 31, 2004 and 2003, respectively or $.30 per Mcf and $.74 per Mcf of cash settlement payments for the years ended December 31, 2004 and 2003, respectively, for hedges assumed in connection with the Nuevo and 3TEC mergers.

—MORE—

Page 8

PLAINS EXPLORATION & PRODUCTION COMPANY

CONSOLIDATED BALANCE SHEETS

(in thousands of dollars)

	December 31,
	2004			2003
ASSETS
Current Assets
Cash and cash equivalents	$	1,545		$	1,377
Accounts receivable—Plains All American Pipeline, L.P.		26,224			25,344
Other accounts receivable		96,064			25,267
Inventories		8,505			5,318
Deferred income taxes		76,823			28,156
Assets held for sale		44,222			—
Other current assets		4,784			3,019
		258,167			88,481
Property and Equipment, at cost
Oil and natural gas properties—full cost method
Subject to amortization		2,402,179			1,074,302
Not subject to amortization		79,405			63,658
Other property and equipment		12,546			4,939
		2,494,130			1,142,899
Less allowance for depreciation, depletion and amortization		(323,041	)		(186,004	)
		2,171,089			956,895
Goodwill		170,467			147,251
Other Assets		33,522			19,641
	$	2,633,245		$	1,212,268
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	90,469		$	41,736
Commodity derivative contracts		175,473			60,222
Royalties payable		39,174			19,080
Stock appreciation rights		34,589			16,049
Interest payable		13,070			622
Deposit on assets held for sale		40,711			—
Other current liabilities		32,909			17,377
		426,395			155,086
Long-Term Debt
8.75% Senior Subordinated Notes		276,727			276,906
7.125% Senior Notes		248,741			—
Revolving credit facility		110,000			211,000
		635,468			487,906
Other Long-Term Liabilities
Asset retirement obligation		126,850			33,235
Commodity derivative contracts		244,140			23,697
Other		10,534			8,497
		381,524			65,429
Deferred Income Taxes		319,483			149,591
Stockholders’ Equity
Common stock		772			403
Additional paid-in capital		913,466			322,856
Retained earnings		80,406			71,566
Accumulated other comprehensive income		(123,874	)		(40,439	)
Treasury stock, at cost		(395	)		(130	)
		870,375			354,256
	$	2,633,245		$	1,212,268

—MORE—

Page 9

Plains Exploration & Production Company

Consolidated Statements of Cash Flows

(thousands of dollars)

	Quarter Ended December 31,						Year Ended December 31,
	2004			2003			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	27,527		$	12,040		$	8,840		$	59,411
Items not affecting cash flows from operating activities
Depreciation, depletion, amortization and accretion		53,743			17,157			147,985			52,484
Deferred income taxes		4,179			8,094			(7,192	)		32,228
Debt extinguishment costs		—			—			(4,453	)		—
Cumulative effect of adoption of accounting change		—			—			—			(12,324	)
Commodity derivative contracts
Loss (gain) on derivatives		(16,365	)		9,410			49,841			(847	)
Reclassify financing derivative settlements		42,247			—			103,521			—
Noncash compensation
Stock appreciation rights		2,384			10,065			20,268			15,895
Other noncash compensation		1,447			243			8,092			1,190
Other noncash items		(52	)		(229	)		(144	)		123
Changes in assets and liabilities from operating activities		(2,060	)		(26,449	)		36,461			(29,882	)
Net cash provided by operating activities		113,050			30,331			363,219			118,278
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition, exploration, development and other costs		(69,288	)		(27,046	)		(211,387	)		(122,070	)
Acquisition of Nuevo Energy Company		—			—			(14,156	)		—
Acquisition of 3TEC Energy Corporation		—			(349	)		—			(267,546	)
Proceeds from property sales		153,097			14,903			238,989			23,420
Other		(2,293	)		(755	)		(8,032	)		(2,514	)
Net cash provided by (used in) investing activities		81,516			(13,247	)		5,414			(368,710	)
CASH FLOWS FROM FINANCING ACTIVITIES
Change in revolving credit facilities		(153,000	)		(15,200	)		(101,000	)		175,200
Proceeds from debt issuance		—			—			248,695			80,061
Retirement of debt assumed in acquisition of
Nuevo Energy Company		—			—			(405,000	)		—

Debt issuance costs		(337	)		(206	)		(9,325	)		(4,349	)
Derivative settlements		(42,247	)		—			(103,521	)		—
Other		773			(305	)		1,686			(131	)
Net cash provided by (used in) financing activities		(194,811	)		(15,711	)		(368,465	)		250,781
Net increase (decrease) in cash and cash equivalents		(245	)		1,373			168			349
Cash and cash equivalents, beginning of period		1,790			4			1,377			1,028
Cash and cash equivalents, end of period	$	1,545		$	1,377		$	1,545		$	1,377

#  #  #