PXP Announces Second Quarter 2005 Results and Increased 2005 Capital Budget

HOUSTON, Aug. 8 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company ("PXP" or the "Company") today reported second quarter 2005 production of 67.7 thousand barrels of oil equivalent per day (BOEPD) compared to second quarter 2004 production of 58.5 thousand BOEPD. Operating cash flow, a non-GAAP measure, was $83.6 million in the second quarter of 2005 compared to $51.6 million in the second quarter of 2004. See the last page of this release for an explanation and reconciliation of non-GAAP financial measures.

Due primarily to a previously disclosed mark-to-market charge for derivative fair value losses associated with the rise in oil prices during the quarter and a change in the estimated tax rate for 2005, PXP reported a net loss of $47.3 million, or $0.61 per share, for the second quarter of 2005 compared to net income of $18.9 million, or $0.32 per share for the second quarter of 2004. In the quarter, PXP recognized a pre-tax loss on mark-to- market derivative contracts of $113.9 million ($1.46 per share). Cash payments related to these contracts that settled in the second quarter totaled $50.9 million ($0.65 per share). In addition, PXP recorded non-cash charges to revenue of $18.4 million ($0.24 per share) related to certain oil and gas hedges. Second quarter results also include pre-tax charges related to stock- based compensation of $6.8 million ($0.09 per share). PXP revised its estimated 2005 effective tax rate to a 35% benefit from a 40% benefit that was utilized in the first quarter. Due to the change, the second quarter reported tax rate was only 1%.

"PXP continues to move aggressively toward building a stronger business. We completed the previously announced property acquisition and disposition transactions as well as the elimination of our 2006 swap and collar positions. We have also increased our 2005 capital budget from $375 million to $425 million, including capitalized interest and G&A, to primarily accommodate additional activity in the Gulf of Mexico and PXP's anticipated acquisition of Chevron's interest at Point Arguello. These activities are part of our efforts to remain focused on core objectives of growth, margins and flexibility," 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 $42.42 during the second quarter of 2005 compared to $33.25 in the second quarter of 2004. Cash payments related to hedging and derivative transactions that settled during the quarter were $12.51 per BOE in 2005 compared to $8.50 in 2004.

Total production costs were $11.34 per BOE in the second quarter of 2005, compared to $9.22 per BOE in 2004. The increase is primarily attributable to steam gas costs for the San Joaquin Valley production acquired through the Nuevo merger that was completed in May 2004. Lease operating expenses, a component of total production costs, were $5.99 per BOE, above the high end of the guidance range of $5.50 per BOE. Lease operating expenses were impacted by generally higher costs in the field and workover expenses associated with the California producing properties acquired in April.

General and administrative costs for the quarter, excluding stock based compensation, were $11.5 million, in line with expectations. G&A expenses increased from $8.5 million for the second quarter of 2004 primarily due to the acquisition of Nuevo and to a lesser extent costs associated with compliance with the Sarbanes-Oxley Act.

For the first six months of 2005 PXP reported production of 67.0 thousand BOEPD compared to 48.1 thousand BOEPD for the first six months of 2004. Operating cash flow, a non-GAAP measure, was $161.7 million in the first six months of 2005 compared to $91.0 million in the first six months of 2004.

PXP reported a net loss of $252.9 million, or $3.27 per share, for the first six months of 2005 as a result of $487.9 million ($4.09 per share) of derivative fair value losses. Cash payments related to 2005 contracts that settled in the first half of the year totaled $87.9 million. In addition, PXP made cash payments of approximately $145.4 million to eliminate our 2006 oil price collars. The first six months include non-cash charges to revenue of $33.8 million ($0.28 per share) related to certain oil and gas hedges as well as pre-tax charges related to stock-based compensation of $32.6 million ($0.27 per share).

The average realized sales price per BOE before hedging and derivative transactions was $40.84 during the first six months of 2005 compared to $32.87 in 2004. Cash payments related to hedging and derivative transactions that settled during the period were $11.82 per BOE in 2005 compared to $7.73 in 2004.

Oil and gas capital expenditures for the second quarter were $113.3 million compared to $56.5 million for the prior year period. For the six months ended June 30, 2005, oil and gas capital expenditures were $202.6 million compared to $88.7 million for the prior year period. These amounts exclude the cost of acquisitions.

During the second quarter the Company amended its revolving credit facility to increase the facility size and provide additional flexibility. The amended credit facility increased the facility size to $750.0 million, established an initial borrowing base of $750.0 million and extended the maturity date to May 2010. Long term debt increased to $751.9 million at the end of the quarter, compared to $668.8 million as of March 31, 2005, as a result of the acquisition of California producing properties completed during the quarter.

Operational Update

In PXP's Eastern Development Unit, two discoveries were placed on line to sales in the second quarter. The Queen Bess Island Prospect, announced in March as a discovery in Jefferson Parish, Louisiana, began production in late May and is currently producing at a 14.9 million cubic feet per day (MMCFD) gross rate. PXP operates the well with an income interest of approximately 41 percent. PXP has identified two additional prospects as follow ups in the field area with one currently drilling. In the federal waters portion of Breton Sound, the Battle Prince Prospect was completed as a new discovery in late April and began first production at the end of June with current production at 17.8 gross MMCFD. PXP's income interest is approximately 41 percent. At least three additional Breton Sound area prospects are expected to be drilled in the second half of 2005.

In a newer exploration area for PXP in the Middle/Lower Miocene Trend of the Green Canyon-Walker Ridge portion of the deep water Gulf of Mexico, PXP has participated in one test well at the Chilkoot Prospect which was drilled to a depth greater than 30,000' and temporarily abandoned in the second quarter. PXP is currently participating in two other similar depth wells which are now drilling. PXP's working interest in the wells and prospects in this area range from 12-1/2 to 17-1/2 percent.

In the San Joaquin Valley (SJV) of California, PXP has drilled approximately 140 wells through the end of July consisting of 39 wells in Midway Sunset Field, 85 wells in Cymric Field, and the remainder in other SJV fields. The Midway Sunset Field drilling is largely on PXP's Bremer Fee property where operations are being expanded from the main historical steam- flood horizon in the Potter Sand into previously under-developed Marvic, Spellacy, A-1, and O Sands. These sands are presently un-steamed and "cold," however, over the next five years, total Bremer lease new sand development oil rates are expected to build to over 3,500 barrels of oil per day (BOPD) from about 225 new wells. In the Cymric Field, 2005 drilling has consisted of 42 thermal Diatomite producers and another 43 thermal sand producer or injector wells. Completion and steam cycle operations are underway with Cymric Field production now at 11,650 net BOPD, up from 9,300 net BOPD during the second quarter. PXP's working interest in the Midway Sunset and Cymric Fields is typically 100 percent.

In the deep portion of the Inglewood Field in the Los Angeles Basin, PXP has completed a total of approximately 30 wells below the Vickers-Rindge water-flood horizon as of the end of July. Included in that total are 23 wells in the Sentous Formation which is typically the deepest productive zone and an additional 7 wells in the Moynier Formation. PXP is completing several of the Moynier wells as injectors to begin a pattern waterflood with initial water injection expected to begin in the third quarter. PXP is currently operating 3 drilling rigs in the Inglewood Field. July total Inglewood production was approximately 8,400 net BOEPD, compared to 6,921 net BOEPD in the second quarter of 2004. PXP's working interest in the Inglewood Field is typically 100 percent.

At PXP's Rocky Point development program offshore California, the third extended reach development well encountered two previously unmapped downthrown faults and was structurally lower than originally planned, resulting in a low volume well. Operations have now commenced to side-track drill this well. In addition workover operations on the second Rocky Point well are just concluding. Based on as-experienced drilling parameters for the first three Rocky Point wells, future wells will be drilled with a more nearly-horizontal trajectory through the reservoir allowing more feet of productive reservoir exposure than anticipated in the original development plan. Additionally, PXP has reached an agreement with Chevron to acquire their approximate 16.7 percent working interest in the Rocky Point development. Closing is subject to normal conditions and expected to occur in September. Upon closing, PXP's working interest at Point Arguello and Rocky Point will be approximately 69.3 percent.

Derivative Position Update

During the second quarter the Company completed the previously announced transactions to eliminate its 2006 oil price swaps and collars and paid the $292.7 million due under the contracts. This payment reduced derivative liabilities on the Company's balance sheet. In the Company's second quarter statement of cash flows the $145.4 million cash payment for the collars is reflected as a financing cash outflow and the $147.3 million cash payment for the swaps is reflected as an operating cash outflow. The payment with respect to the collars is reflected as a financing cash outflow because under FAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, the collars are deemed to contain a significant financing element since they included off-market terms.

Although the Company eliminated its 2006 swap and collar positions, it still has oil collars for the remainder of 2005 and the years 2007 and 2008 that are subject to mark-to-market accounting. In addition, the Company has purchased put contracts with a strike price of $45 NYMEX WTI with respect to 50,000 barrels per day in 2006 and 20,000 barrels per day in 2007 that are also subject to mark-to-market accounting. Consequently, the Company expects that there will continue to be volatility in its reported earnings due to gains and losses on mark-to-market derivative contracts as changes occur in the NYMEX price index.

2005 Outlook

PXP plans to issue updated annual guidance for 2005 via Form 8-K today to reflect an increase in lease operating expenses, non-cash compensation and the 2005 capital budget.

PXP will host a conference call to discuss the results and other forward- looking items at 2:00 p.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 August 22, 2005 and can be accessed by dialing 1-877-519-4471 or 1-973-341-3080, Replay ID: 6295816.

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:

* 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 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.

Plains Exploration & Production Company Consolidated Statements of Income (amounts in thousands, except per share data) Three Months Ended Six Months Ended June 30, June 30, 2005 2004 2005 2004 Revenues Oil sales $162,672 $99,564 $297,385 $148,835 Gas sales 53,898 52,708 108,377 96,162 Other operating revenues 738 498 1,621 734 217,308 152,770 407,383 245,731 Costs and Expenses Production costs Lease operating expenses 36,877 28,604 69,205 47,565 Steam gas costs 16,404 7,354 33,085 8,311 Electricity 8,186 6,751 14,761 12,513 Production and ad valorem taxes 5,967 4,580 13,303 8,553 Gathering and transportation expenses 2,404 1,790 5,949 2,986 General and administrative G&A excluding items below 11,511 8,466 23,238 15,510 Stock appreciation rights 2,905 2,865 25,877 13,426 Other stock-based compensation 3,926 1,891 6,755 4,378 Depletion, depreciation, and amortization 45,745 29,991 89,338 45,831 Accretion expense 1,934 1,877 3,679 2,604 135,859 94,169 285,190 161,677 Income from Operations 81,449 58,601 122,193 84,054 Other Income (Expense) Gain (loss) on mark-to-market derivative contracts (113,871) 374 (487,923) (1,191) Loss on debt extinguishment --- (19,691) --- (19,691) Interest expense (14,158) (8,607) (25,561) (15,537) Interest and other income (120) 43 172 305 Income (Loss) Before Income Taxes (46,700) 30,720 (391,119) 47,940 Income tax (expense) benefit Current (1,330) 44 (1,330) (144) Deferred 700 (11,871) 139,501 (18,505) Net Income (Loss) $(47,330) $18,893 $(252,948) $29,291 Earnings (Loss) per Share Basic $(0.61) $0.32 $(3.27) $0.59 Diluted $(0.61) $0.32 $(3.27) $0.58 Weighted Average Shares Outstanding Basic 77,329 59,602 77,266 49,925 Diluted 77,329 59,925 77,266 50,207 Plains Exploration & Production Company Operating Data Three Months Ended Six Months Ended June 30, June 30, 2005 2004 2005 2004 Total Period Production Oil and Liquids (MBbls) 4,740 3,746 9,157 5,942 Gas (MMcf) 8,501 9,464 17,778 16,868 MBOE 6,157 5,323 12,120 8,753 Average Daily Production Oil and Liquids (Bbls) 52,088 41,165 50,593 32,648 Gas (Mcf) 93,417 104,000 98,219 92,681 BOE 67,658 58,498 66,963 48,093 Unit Economics (in dollars) Average NYMEX Prices Oil $53.13 $38.34 $51.53 $36.75 Henry Hub gas 6.73 6.01 6.50 5.84 Average Realized Sales Price Before Hedging Oil (per Bbl) $43.56 $32.61 $42.22 $32.06 Gas (per Mcf) 6.43 5.79 6.10 5.76 Per BOE 42.42 33.25 40.84 32.87 Production expenses per BOE Lease operating expenses $5.99 $5.37 $5.71 $5.43 Steam gas costs 2.66 1.38 2.73 0.95 Electricity 1.33 1.27 1.22 1.43 Production and ad valorem taxes 0.97 0.86 1.10 0.98 Gathering and transportation expenses 0.39 0.34 0.49 0.34 Cash payments related to 2005 and 2004 derivative contracts that settled during the periods were as follows ($/millions): Contracts accounted for using hedge accounting Oil $24.9 $36.8 $53.0 $55.8 Gas 1.3 3.8 2.4 6.3 Mark-to-market contracts 50.9 4.6 87.9 5.6 PLAINS EXPLORATION & PRODUCTION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands of dollars) June 30, December 31, 2005 2004 ASSETS Current Assets Cash and cash equivalents $969 $1,545 Accounts receivable 128,282 122,288 Inventories 10,625 8,505 Deferred income taxes 122,033 76,823 Assets held for sale --- 44,222 Other current assets 6,912 4,784 268,821 258,167 Property and Equipment, at cost Oil and natural gas properties - full cost method Subject to amortization 2,388,244 2,402,179 Not subject to amortization 90,565 79,405 Other property and equipment 15,142 12,546 2,493,951 2,494,130 Less allowance for depreciation, depletion and amortization (410,834) (323,041) 2,083,117 2,171,089 Goodwill 172,558 170,467 Other Assets 34,760 33,522 $2,559,256 $2,633,245 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts payable $99,152 $90,469 Commodity derivative contracts 208,698 175,473 Royalties payable 38,958 39,174 Stock appreciation rights 54,681 34,589 Interest payable 13,328 13,070 Deposit on assets held for sale --- 40,711 Other current liabilities 31,260 32,909 446,077 426,395 Long-Term Debt 8.75% Senior Subordinated Notes 276,634 276,727 7.125% Senior Notes 248,788 248,741 Revolving credit facility 226,500 110,000 751,922 635,468 Other Long-Term Liabilities Asset retirement obligation 141,622 126,850 Commodity derivative contracts 354,293 244,140 Other 7,257 10,534 503,172 381,524 Deferred Income Taxes 223,962 319,483 Stockholders' Equity Common stock 775 772 Additional paid-in capital 924,956 913,466 Retained earnings (deficit) (172,600) 80,406 Accumulated other comprehensive income (119,008) (123,874) Treasury stock, at cost --- (395) 634,123 870,375 $2,559,256 $2,633,245 Plains Exploration & Production Company Consolidated Statements of Cash Flows (thousands of dollars) Six Months Ended June 30, 2005 2004 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $(252,948) $29,291 Items not affecting cash flows from operating activities Depreciation, depletion, amortization and accretion 93,017 48,435 Deferred income taxes (139,501) 18,505 Debt extinguishment costs --- (4,453) Commodity derivative contracts Loss (gain) on derivatives 291,914 (18,571) Reclassify financing derivative settlements 270,742 19,762 Noncash compensation Stock appreciation rights 16,900 3,573 Other noncash compensation 7,014 14,300 Other noncash items (46) (79) Changes in operating assets and liabilities Commodity derivative contracts (142,938) 11,140 Other (30,686) (3,030) Net cash provided by operating activities 113,468 118,873 CASH FLOWS FROM INVESTING ACTIVITIES Exploration, development and other costs (180,764) (78,416) Acquisition of oil and gas properties (118,375) --- Acquisition of Nuevo, net of cash acquired --- (13,744) Proceeds from property sales 340,969 27,844 Other (2,596) (5,202) Net cash used in investing activities 39,234 (69,518) CASH FLOWS FROM FINANCING ACTIVITIES Change in revolving credit facilities 116,500 142,000 Proceeds from debt issuance --- 248,695 Retirement of debt assumed in acquisition of Nuevo --- (405,000) Debt issuance costs (1,490) (7,799) Derivative settlements (270,742) (19,762) Other 2,454 (183) Net cash used in financing activities (153,278) (42,049) Net increase (decrease) in cash and cash equivalents (576) 7,306 Cash and cash equivalents, beginning of period 1,545 1,377 Cash and cash equivalents, end of period $969 $8,683 Plains Exploration & Production Company Summary of Open Derivative Positions July 1, 2005 Instrument Daily Average Period Commodity Type Volumes Price Index Sales of Production Qualified for Hedge Accounting 2005 July - Dec Natural gas Swap 5,000 /MMBtu $4.40 Waha Not Qualified for Hedge Accounting 2005 $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- July - Dec Crude oil Collar 22,000 /Bbls $34.76 Ceiling WTI 2006 Put Jan - Dec Crude oil options 50,000 /Bbls $45.00 WTI 2007 $25.00 Floor- Jan - Dec Crude oil Collar 22,000 /Bbls $34.76 Ceiling WTI Put Jan - Dec Crude oil 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 Qualified for Hedge Accounting 2005 July - Dec Natural gas Swap 8,000 /MMBtu $3.85 Socal Plains Exploration & Production Company Operating Cash Flow Reconciliation of GAAP to Non-GAAP Measure

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 Six Months Ended Ended June 30, June 30, 2005 2004 2005 2004 (millions of dollars) Net cash provided by operating activities (GAAP) $15.7 $88.5 $113.5 $118.9 Changes in operating assets and liabilities Commodity derivative contracts 145.9 (8.8) 142.9 (11.1) Other (3.4) (8.3) 30.7 3.0 Cash payments for commodity derivative contracts that settled during the period that are reflected as financing cash flows in the statement of cash flows (74.6) (19.8) (125.4) (19.8) Operating cash flow (Non-GAAP) $83.6 $51.6 $161.7 $91.0 2005 1st Qtr 2nd Qtr 6 Months (millions of dollars) Net cash provided by operating activities (GAAP) $97.8 $15.7 $113.5 Changes in operating assets and liabilities Commodity derivative contracts (3.0) 145.9 142.9 Other 34.1 (3.4) 30.7 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) (125.4) Operating cash flow (Non-GAAP) $78.1 $83.6 $161.7

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.