PXP Announces Third Quarter 2005 Results

HOUSTON, Nov. 3 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company ("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.

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; * $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 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.

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 Nine Months Ended September 30, 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 Plains Exploration & Production Company Operating Data Three Months Nine Months Ended Ended September 30, 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 PLAINS EXPLORATION & PRODUCTION COMPANY CONSOLIDATED BALANCE SHEETS (in thousands of dollars) September 30, December 31, 2005 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 Plains Exploration & Production Company Consolidated Statements of Cash Flows (thousands of dollars) Three Months Ended Nine Months Ended September 30, 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 Plains Exploration & Production Company Summary of Open Derivative Positions Instrument Daily Average Period Commodity Type Volumes 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 WTI Strike price 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 WTI Strike price 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 Socal Strike price 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 Nine Months Ended September 30, 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.

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 Nine Months 2005 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.