PXP Announces Third Quarter 2006 Results, 2007 Capital Budget and 2007 Guidance

HOUSTON, Nov. 9 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company ("PXP" or the "Company") today announced financial and operating results for the third quarter, a $600 million 2007 capital budget, and operational guidance for the full-year 2007. During 2006, PXP is on track to reduce its share count, increase its shareholders equity and reduce leverage.

Highlights of recent accomplishments include: * Completed two asset sales worth $1.6 billion to PXP: In September PXP received $864 million for certain California and Texas producing properties which accounted for about 11 percent of 2005 year-end proved reserves. In November PXP received $706 million for two 2006 Gulf of Mexico deepwater Miocene discoveries and one deepwater prospect which have no proved reserves as of year-end 2005. * Increased operating cash flow by 97 percent year-over-year: $170.0 million compared to $86.3 million (a non-GAAP measure) * Increased cash margin per BOE by 82 percent year-over-year: $36.98 compared to $20.37 (a non-GAAP measure) * Tendered and redeemed substantially all of the 8.75 percent Senior Subordinated Notes and all of the 7.125 percent Senior Notes. THREE MONTHS ENDED SEPTEMBER 30

PXP reported revenues of $280.9 million for the third quarter 2006 compared to $262.6 million for the third quarter 2005. Operating cash flow, a non-GAAP measure, increased 97 percent to $170.0 million in the third quarter of 2006 compared to $86.3 million in the prior year period. Cash margin, a non-GAAP measure, was $36.98 per BOE in the third quarter of 2006 compared to $20.37 per BOE in 2005. See the end of this release for an explanation and reconciliation of all non-GAAP financial measures.

PXP reported net income of $272.7 million, or $3.50 per diluted share, compared to a net loss of $31.8 million, or $0.41 per diluted share for the third quarter 2005. Net income for the period includes a $345.5 million pre- tax gain on the sale of oil and gas properties, a $12.3 million pre-tax gain on mark-to-market derivative contracts (cash payments related to the put and call option premiums during the quarter totaled $25.5 million), a $36.5 million pre-tax non cash charge to revenue related to certain oil hedges, and a $13.2 million pre-tax charge related to stock-based compensation.

Without the effects of these items net income for the third quarter of 2006 would have been $70.8 million, or $0.91 per diluted share, compared to $29.0 million, or $0.37 per diluted share in 2005.

Sales volumes during the third quarter 2006 were 60.6 thousand barrels of oil equivalent per day (BOEPD) compared to sales volumes of 59.2 thousand BOEPD during third quarter 2005.

Total production costs were $15.30 per BOE in the third quarter of 2006 compared to $12.50 per BOE in 2005. The increase per unit is primarily attributable to higher lease operating costs, due to general cost increases from service providers and utilities, as well as higher expenditures for repairs, maintenance and well workovers.

NINE MONTHS ENDED SEPTEMBER 30

PXP reported revenues of $810.9 million for the first nine months of 2006 compared to $670.0 million in 2005. Operating cash flow, a non-GAAP measure, nearly doubled to $495.5 million in the first nine months of 2006 compared to $248.0 million reported in the prior year period. Cash margin, a non-GAAP measure, was $36.62 per BOE in the first nine months of 2006 compared to $18.60 per BOE in 2005.

For the first nine months of 2006 PXP reported net income of $213.9 million, or $2.71 per diluted share, compared to a net loss of $284.8 million, or $3.67 per diluted share for the same period a year ago. Net income for the period includes a $345.5 million pre-tax gain on the sale of oil and gas properties, a $299.9 million pre-tax loss on mark-to-market derivative contracts (cash payments related to the put and call option premiums during the period totaled $75.6 million), a $109.6 million pre-tax non cash charge to revenue related to certain oil hedges, a $42.2 million pre-tax charge related to stock-based compensation, and a $37.9 million pre-tax gain on termination of merger agreement between PXP and Stone.

Without the effects of these items net income for the nine months of 2006 would have been $212.0 million, or $2.69 per diluted share, compared to $76.6 million or $0.98 per diluted share in 2005.

Sales volumes for the first nine months of 2006 were 61.0 thousand BOEPD compared to 62.7 thousand BOEPD in 2005. Sales volumes were lower year-over- year primarily due to asset sales in the second quarter 2005.

Total production costs were $14.00 per BOE for the first nine months of 2006 compared to $11.64 per BOE in 2005. The increase per unit is primarily attributable to lower volumes and higher lease operating costs, due to general cost increases from service providers, and higher expenditures for repairs, maintenance and well workovers.

Oil and gas capital expenditures, excluding acquisitions, were $474.3 million for the first nine months of 2006 compared to $315.1 million for the prior year period. The increase is primarily attributed to additional exploratory opportunities in the Gulf of Mexico.

BALANCE SHEET UPDATE

PXP completed property sales transactions in September and November 2006 generating approximately $1.6 billion of cash proceeds. The proceeds were used to repay the balance outstanding on its senior revolving credit facility and short-term credit facility, redeem all $250 million outstanding principal of its 7.125 percent Senior Notes, purchase substantially all $275 million outstanding principal of its 8.75 percent Senior Subordinated Notes, and complete the previously announced $605 million hedge liability termination.

Through July 2006 PXP repurchased 2,461,900 common shares at a cost of $100.8 million with $399.2 million remaining under the $500 million authorization. The Company expects to continue repurchasing shares from time to time in open market transactions or privately negotiated transactions at its discretion, subject to market conditions and other factors.

DEVELOPMENT - OPERATIONS UPDATE

In the Los Angeles Basin, PXP's exit rate for the third quarter was approximately 16,200 net BOEPD. A total of 60 of the 68 planned wells have been drilled through the end of the third quarter. Drilling activity this year has been concentrated in the Inglewood Field on the Vickers-Rindge waterflood zone with 49 of the 60 wells drilled and expanding the development in the Moynier and Rubel formations. The remaining wells for the 2006 plan will focus on the Moynier and Rubel zones and the Las Cienegas Field.

In the San Joaquin Valley, PXP's exit rate for the third quarter 2006 was approximately 25,500 net BOEPD. A total of 130 of the 155 planned wells have been drilled through the end of the third quarter. In the Midway Sunset Field, 51 wells have been drilled with 17 planned for the fourth quarter. In the Cymric Field, 70 wells have been drilled as of the end of the third quarter which ends the 2006 drilling program at Cymric. Drilling will begin in November at the Arroyo Grande Field with a total of 8 wells planned for the fourth quarter.

Offshore California, PXP's exit rate for the third quarter 2006 was approximately 13,600 net BOEPD. At PXP's Point Pedernales Field, three of four planned in-fill wells are producing and completion operations for the fourth well are now underway.

In the Gulf Coast region, PXP's exit rate for the third quarter 2006 was approximately 6,100 net BOEPD. PXP is participating in one additional well this year.

PXP completed the sale of certain California and Texas producing properties on September 29, 2006. The transaction is effective October 1, 2006. The Company's exit rate for the third quarter excluding the properties sold was 54,000 net BOEPD.

EXPLORATION - OPERATIONS UPDATE

PXP completed the previously announced sale of two 2006 Gulf of Mexico Miocene trend discoveries on November 1, 2006 for total cash consideration of $706 million. The transaction is effective September 1, 2006 and the Company expects to record a gain in the fourth quarter.

In the Gulf of Mexico Miocene trend, PXP is currently participating in two deepwater exploratory tests, the Friesian Prospect (Shell operator: PXP 20%) and the Norman Prospect (Anadarko operator: PXP 15%).

2007 CAPITAL BUDGET

The Board of Directors approved a $600 million 2007 capital budget with approximately 50 percent to be utilized for continued development of the Company's California oil fields and the balance for high impact exploration projects, primarily targeting the Miocene trend in the Gulf of Mexico. Depending on project timing, as much as $55 million of the 2007 capital budget may be spent in late 2006.

As part of its balanced approach to creating shareholder value, PXP plans to drill approximately 200 development wells in its legacy oil fields located in the Los Angeles, San Joaquin, and Santa Maria Basins onshore and offshore California. These projects have solid economic returns, provide reserve additions, and generate substantial cash flow per share. The drilling success for development projects so far in 2006 has been 99 percent. PXP will continue to develop the large Inglewood Field complex, including Las Cienegas, in the Los Angeles Basin with waterflood development drilling. The San Joaquin Valley fields, Cymric, Midway Sunset, South Belridge, and Arroyo Grande area drilling includes expansion of existing tertiary recovery steamfloods, as well as development of new steam projects.

Continuing with the exploration success PXP has had in the Gulf of Mexico Miocene trend, the Company's current inventory now includes up to 30 to 35 high impact prospects. PXP intends to continue focusing its exploration expertise in the Miocene trend by participating in 10 of these prospects during 2007. These consist of Gulf of Mexico deepwater prospects and prospects located near existing infrastructure. The Miocene prospects near infrastructure are part of a recent agreement with McMoRan Exploration whereby PXP plans to participate in up to 9 exploratory tests in 2007.

OUTLOOK

The Company reaffirms its previously issued fourth quarter 2006 operational guidance and issues full-year 2007 operational guidance as attached at the end of this release. Full-year 2007 financial guidance will be issued in early 2007.

THIRD QUARTER EARNINGS CONFERENCE CALL

PXP will host a conference call tomorrow November 10, 2006 at 9:00 a.m. Central to discuss results and other forward-looking items. Investors wishing to participate may dial 1-800-567-9836 or 1-973-935-8460. The replay will be available through November 24, 2006 and can be accessed by dialing 1-877-519- 4471 or 1-973-341-3080, Replay ID: 8006955. Slides for the conference call will be available in the Investor Information section of PXP's website, http://www.plainsxp.com/ , during the conference call and for 60 days after the event date.

PXP is an independent oil and gas company primarily engaged in the upstream activities of acquiring, developing, exploiting, exploring and producing oil and gas in its core areas of operation: onshore and offshore California, 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, 2005, 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 and our other filings with the SEC. 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, 2006 2005 2006 2005 Revenues Oil sales $253,844 $217,747 $718,841 $515,132 Gas sales 26,724 44,231 89,879 152,608 Other operating revenues 339 641 2,192 2,262 280,907 262,619 810,912 670,002 Costs and Expenses Production costs Lease operating expenses 50,355 36,284 137,258 105,489 Steam gas costs 15,707 17,932 41,327 51,017 Electricity 9,991 8,917 28,777 23,678 Production and ad valorem taxes 6,991 5,111 19,795 18,414 Gathering and transportation expenses 2,291 2,467 5,947 8,416 General and administrative 31,493 52,764 92,530 108,634 Depreciation, depletion and amortization 50,844 40,626 151,528 129,964 Accretion 2,564 1,926 7,506 5,605 Gain on sale of oil and gas properties (345,480) --- (345,480) --- (175,244) 166,027 139,188 451,217 Income from Operations 456,151 96,592 671,724 218,785 Other Income (Expense) Interest expense (22,178) (14,478) (57,182) (40,039) Gain (loss) on mark-to-market derivative contracts 12,340 (141,646) (299,902) (629,569) Gain on termination of merger agreement --- --- 37,902 --- Interest and other income (expense) 500 (392) 2,120 (220) Income (Loss) Before Income Taxes and Cumulative Effect of Accounting Change 446,813 (59,924) 354,662 (451,043) Income tax (expense) benefit Current (47,490) 757 (56,247) (573) Deferred (126,630) 27,318 (82,319) 166,819 Income (Loss) Before Cumulative Effect of Accounting Change 272,693 (31,849) 216,096 (284,797) Cumulative effect of accounting change, net of tax --- --- (2,182) --- Net Income (Loss) $272,693 $(31,849) $213,914 $(284,797) Earnings (Loss) Per Share Basic Income (loss) before cumulative effect of accounting change $3.56 $(0.41) $2.77 $(3.67) Cumulative effect of accounting change --- --- (0.03) --- Net income (loss) $3.56 $(0.41) $2.74 $(3.67) Diluted Income (loss) before cumulative effect of accounting change $3.50 $(0.41) $2.74 $(3.67) Cumulative effect of accounting change --- --- (0.03) --- Net income (loss) $3.50 $(0.41) $2.71 $(3.67) Weighted Average Shares Outstanding Basic 76,622 78,053 77,911 77,531 Diluted 77,802 78,053 78,802 77,531 Plains Exploration & Production Company Operating Data Three Months Ended Nine Months Ended September 30, September 30, 2006 2005 2006 2005 Daily Average Volumes Oil and liquids sales (Bbls) 53,043 50,374 52,815 50,520 Gas (Mcf) Production 62,266 66,687 63,782 87,593 Used in steam operations 16,721 13,730 14,732 14,670 Sales (A) 45,545 52,957 49,050 72,923 BOE Production 63,421 61,487 63,445 65,117 Sales (A) 60,634 59,196 60,990 62,674 Unit Economics (in dollars) (B) Average NYMEX Prices Oil $70.54 $63.16 $68.25 $55.45 Gas 6.62 8.52 7.44 7.18 Average Realized Sales Price Before Derivative Transactions Oil (per Bbl) $59.51 $52.53 $57.46 $45.69 Gas (per Mcf) 6.38 7.37 6.71 6.43 Per BOE 56.85 51.03 55.16 44.08 Cash Margin per BOE (C) Oil and gas revenues $50.30 $46.32 $48.57 $37.56 Costs and expenses Lease operating expenses (9.03) (6.41) (8.24) (5.93) Steam gas costs (2.82) (3.17) (2.48) (2.87) Electricity (1.79) (1.58) (1.73) (1.33) Production and ad valorem taxes (1.25) (0.90) (1.19) (1.04) Gathering and transportation (0.41) (0.44) (0.36) (0.47) Gross margin before DD&A (GAAP) 35.00 33.82 34.57 25.92 Hedging expense included in oil and gas revenues 6.55 4.72 6.58 6.52 Cash derivative settlements Oil & gas production (4.05) (18.17) (4.02) (13.84) Natural gas purchases (0.52) --- (0.51) --- Cash margin (Non-GAAP) $36.98 $20.37 $36.62 $18.60 (A) 2005 amounts represent volumes presented on a basis consistent with 2006. See Note 2. (B) In 2005 gas revenues included amounts attributable to buy-sell contracts related to our thermal recovery operations in California and associated costs were included in steam gas costs. As a result of our adoption of EITF 04-13 effective January 1, 2006, in 2006 certain costs associated with such contracts are reflected as a reduction in gas revenues and the associated volumes are not included in sales volumes. Amounts per BOE reflected in the foregoing table are based on production volumes for 2005 and sales volumes for 2006. (C) Cash margin (a non-GAAP measure) is calculated by adjusting gross margin before DD&A (a GAAP measure) to exclude hedging expense included in oil and gas revenues and to deduct cash derivative settlements. Management believes this presentation may be helpful to investors as it represents the cash generated by our oil and gas production that is available for, among other things, capital expenditures and debt service. PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but to provide additional information that may be helpful in evaluating the Company's operational trends and performance. Plains Exploration & Production Company Consolidated Balance Sheets (in thousands of dollars) September 30, December 31, 2006 2005 ASSETS Current Assets Cash and cash equivalents $542,249 $1,552 Accounts receivable 132,290 148,691 Inventories 12,591 10,325 Deferred income taxes 284,763 128,816 Assets held for sale 56,101 --- Other current assets 10,137 3,948 1,038,131 293,332 Property and Equipment, at cost Oil and natural gas properties - full cost method Subject to amortization 2,491,035 2,604,892 Not subject to amortization 113,444 112,204 Other property and equipment 20,474 16,282 2,624,953 2,733,378 Less allowance for depreciation, depletion and amortization (647,093) (498,075) 1,977,860 2,235,303 Goodwill 158,620 173,858 Other Assets 42,205 39,449 $3,216,816 $2,741,942 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities Accounts payable $151,813 $122,996 Commodity derivative contracts 337,683 85,596 Royalties and revenues payable 44,813 43,279 Stock appreciation rights 57,290 55,170 Interest payable 11,572 13,000 Income taxes payable 49,395 --- Other current liabilities 36,023 43,957 688,589 363,998 Long-Term Debt Revolving credit facility --- 272,000 8.75% Senior Subordinated Notes 276,388 276,538 7.125% Senior Notes 248,915 248,837 525,303 797,375 Other Long-Term Liabilities Asset retirement obligation 138,789 155,865 Commodity derivative contracts 405,913 440,543 Other 7,256 7,014 551,958 603,422 Deferred Income Taxes 519,414 258,810 Stockholders' Equity Common stock 791 784 Additional paid-in capital 983,079 940,988 Retained earnings (deficit) 80,250 (133,664) Accumulated other comprehensive income (22,169) (89,566) Treasury stock, at cost (110,399) (205) 931,552 718,337 $3,216,816 $2,741,942 Plains Exploration & Production Company Consolidated Statements of Cash Flows (in thousands of dollars) Three Months Ended Nine Months Ended September 30, September 30, 2006 2005 2006 2005 Cash Flows from Operating Activities Net income (loss) $272,693 $(31,849) $213,914 $(284,797) Items not affecting cash flows from operating activities Gain on sale of oil and gas properties (345,480) --- (345,480) --- Depreciation, depletion, amortization and accretion 53,408 42,552 159,034 135,569 Deferred income taxes 126,630 (27,318) 82,319 (166,819) Cumulative effect of adoption of accounting change --- --- 2,182 --- Commodity derivative contracts Loss on derivatives (1,258) 66,924 333,976 358,838 Reclassify derivative settlements 25,463 94,190 96,773 364,932 Noncash compensation 9,176 35,893 32,594 59,807 Other noncash items (16) (23) (64) (69) Change in assets and liabilities from operating activities 73,773 (5,662) 44,904 (179,286) Net cash provided by operating activities 214,389 174,707 620,152 288,175 Cash Flows from Investing Activities Exploration, development and other costs (167,371) (94,239) (456,796) (393,378) Proceeds from sale of oil and gas properties 850,427 2,127 850,427 343,096 Derivative settlements (25,463) --- (68,194) --- Other (2,932) (927) (7,467) (3,523) Net cash provided by (used in) investing activities 654,661 (93,039) 317,970 (53,805) Cash Flows from Financing Activities Revolving credit facilities Borrowings 453,800 341,700 1,182,700 1,092,700 Repayments (684,800) (329,700) (1,454,700) (964,200) Derivative settlements --- (94,190) (28,579) (364,932) Treasury stock purchases (100,817) --- (100,817) --- Other 3,613 859 3,971 1,823 Net cash used in financing activities (328,204) (81,331) (397,425) (234,609) Net decrease in cash and cash equivalents 540,846 337 540,697 (239) Cash and cash equivalents, beginning of period 1,403 969 1,552 1,545 Cash and cash equivalents, end of period $542,249 $1,306 $542,249 $1,306 Plains Exploration & Production Company Summary of Open Derivative Positions at November 1, 2006 Instrument Daily Average Period Type Volumes Price Index Sales of Crude Oil Production 2006 Nov - Dec Put options 50,000 Bbls $55.00 Strike price WTI 2007 Jan - Dec Put options 50,000 Bbls $55.00 Strike price WTI 2008 Jan - Dec Put options 42,000 Bbls $55.00 Strike price WTI Purchases of Natural Gas 2006 Nov - Dec Call options 30,000 MMBtu $12.00 Strike price Socal Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measure

The following chart reconciles Net Cash Provided by Operating Activities (GAAP) to Operating Cash Flow (non-GAAP) for the three months and nine months ended September 30, 2006 and 2005. Management believes this presentation may be useful to investors because it is illustrative of the impact of the Company's derivative contracts. PXP management uses this information for comparative purposes within the industry and as a means of measuring the Company's ability to fund capital expenditures and service debt. This measure is not intended to replace the GAAP statistic but to provide additional information that may be helpful in evaluating the Company's operational trends and performance.

Operating cash flow is calculated by adjusting the GAAP measure of cash provided by operating activities to exclude the gain on termination of the merger agreement, the effect of current income taxes on the gain on the sale of oil and gas properties and changes in operating assets and liabilities and include derivative cash flows that are classified as a financing or investing 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 following tables do not include the $145.4 million that we paid in the second quarter of 2005 to eliminate our 2006 collar positions.

Three Months Ended September 30, 2006 2005 (millions of dollars) Net cash provided by operating activities (GAAP) $214.4 $174.7 Changes in operating assets and liabilities (73.8) 5.7 Current income taxes on gain on sale of oil and gas properties 54.9 --- Cash payments for commodity derivative contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows (25.5) (94.1) Operating cash flow (Non-GAAP) $170.0 $86.3 Nine Months Ended September 30, 2006 2005 (millions of dollars) Net cash provided by operating activities (GAAP) $620.2 $288.2 Changes in operating assets and liabilities (44.9) 179.3 Current income taxes on gain on sale of oil and gas properties 54.9 --- Gain on termination of merger agreement (37.9) --- Cash payments for commodity derivative contracts that settled during the period that are reflected as investing or financing cash flows in the statement of cash flows (96.8) (219.5) Operating cash flow (Non-GAAP) $495.5 $248.0 Plains Exploration & Production Company Reconciliation of GAAP to Non-GAAP Measure

The following table reconciles net income (loss) (GAAP) to net income (loss) excluding certain items (Non-GAAP) for the three months and nine months ended September 30, 2006 and 2005. This measure excludes certain items that management believes affect the comparability of operating results. Items excluded are generally items whose timing or amount cannot be reasonably estimated or are nonrecurring. Management believes this presentation may be helpful to investors who want to isolate the impacts from oil and gas derivative contracts and stock-based compensation. PXP management uses this information to analyze operating trends and for comparative purposes within the industry. This measure is not intended to replace the GAAP statistic but to provide additional information that may be helpful in evaluating the Company's operational trends and performance.

Three Months Ended September 30, 2006 2005 (millions of dollars) Net income (loss) before cumulative effect (GAAP) $ 272.7 $(31.9) Loss (gain) on mark-to-market derivative contracts (12.3) 141.7 Cash payments on mark-to-market derivative contracts (25.5) (101.4) Non cash charge to revenue for oil and gas hedges 36.6 25.4 Stock-based compensation 13.2 40.2 Gain on sale of oil and gas properties (345.5) --- Gain on termination of merger agreement --- --- Adjust income taxes 131.6 (45.0) Net income (loss) excluding certain items (Non-GAAP) $70.8 $29.0 Nine Months Ended September 30, 2006 2005 (millions of dollars) Net income (loss) before cumulative effect (GAAP) $ 216.1 $(284.8) Loss on mark-to-market derivative contracts 299.9 629.6 Cash payments on mark-to-market derivative contracts (75.6) (189.3) Non cash charge to revenue for oil and gas hedges 109.6 59.2 Stock-based compensation 42.2 72.8 Gain on sale of oil and gas properties (345.5) --- Gain on termination of merger agreement (37.9) --- Adjust income taxes 3.2 (210.9) Net income (loss) excluding certain items (Non-GAAP) $ 212.0 $76.6

The cash payments on mark-to-market derivative contracts in the nine months ended September 30, 2005 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 2007 Operating Guidance The following table and accompanying notes reflect current estimates of certain results for the full year 2007 for PXP. These estimates are based on assumptions and estimates that management believes are reasonable based on currently available information; however, management's assumptions and our future performance are both subject to a wide range of business risks and uncertainties and there is no assurance that these goals and estimates can or will be met. Any number of factors could cause actual results to differ materially from those in the following table and accompanying notes, including but not limited to the factors discussed above. The estimates set forth below are given as of the date hereof only based on information available as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements. Further information on risks and uncertainties is available in our filings with the Securities and Exchange Commission, and we encourage you to review such filings. 2007 Estimated Production Volumes (MBOE/day) Production volumes sold (A) 52.0 - 58.0 % Oil 92% % Gas 8% Price Realization % of Index (unhedged) Oil - NYMEX 82% - 86% Gas - Henry Hub 95% - 100% Production Costs per BOE (A) Lease operating expenses $8.40 - $9.30 Steam gas costs (B) $4.80 - $5.30 Electricity $2.00 - $2.20 Production and ad valorem taxes $1.15 - $1.30 Gathering and transportation $0.03 - $0.05 Capital Expenditures (in thousands) $600,000 (A)Production costs per BOE are calculated using production volumes sold. (B)Steam gas costs assume a base SoCal Border index price of $7.25 per MMBtu. The purchased volumes are anticipated to be 40,000 - 44,000 MMBtu per day.