PXP Announces 2004 Results, Agreement to Purchase $119 Million of Cali

HOUSTON, March 15 /PRNewswire-FirstCall/ -- Plains Exploration & Production Company ("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.

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.

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 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.

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.

Plains Exploration & Production Company Consolidated Statements of Income (amounts in thousands, except per share data) Quarter Ended Year Ended December 31, December 31, 2004 2003 2004 (A) 2003 (B) 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 (C) (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 (A) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004. (B) Reflects the acquisition of 3TEC Energy effective June 1, 2003. (C) 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 $0.8 million for the year then ended. Plains Exploration & Production Company Operating Data Quarter Ended Year Ended December 31, December 31, 2004 2003 2004 (A) 2003 (B) Total Period Production Oil and Liquids (MBbls) 5,267 2,362 16,441 9,267 Gas (MMcf) 10,859 7,367 38,590 18,195 MBOE 7,076 3,590 22,872 12,300 Average Daily Production Oil and Liquids (Bbls) 57,246 25,674 44,920 25,389 Gas (Mcf) 118,027 80,076 105,436 49,849 BOE 76,917 39,022 62,492 33,699 Unit Economics (in dollars) Average Oil & Liquids Sales Price ($/Bbl) Net realized price before hedging $40.19 $27.10 $36.12 $26.92 Hedging revenue (expense) (C) (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) (D) (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 (A) Reflects the acquisition of Nuevo Energy Company effective May 14, 2004. (B) Reflects the acquisition of 3TEC Energy effective June 1, 2003. (C) 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. (D) 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. 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 Plains Exploration & Production Company Consolidated Statements of Cash Flows (thousands of dollars) Quarter Ended Year Ended December 31, 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