Exhibit 99.1

PXP

Lehman Brothers

2005 CEO Energy/Power Conference

September 2005

1

N Y S E : P X P w w w . p l a i n s x p . c o m

Corporate Information

Corporate Headquarters

Plains Exploration & Production Company 700 Milam Suite 3100 Houston, Texas 77002

Contacts

James C. Flores - Chairman, President & CEO

Stephen A. Thorington – EVP & CFO

Scott Winters - Director of Investor Relations

Joanna Pankey - Investor Relations Specialist

Phone: 713-579-6000 Toll Free: 800-934-6083 Email: investor@plainsxp.com Web Site www.plainsxp.com

Forward Looking Statements

Except for the historical information contained herein, the matters discussed in this presentation are “forward-looking statements” as defined by the Securities and Exchange Commission. These statements involve 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.

The forward-looking statements are subject to a number of known and unknown risks, uncertainties and other factors that could cause our actual results to differ materially. These risks and uncertainties include, among other things, uncertainties inherent in the exploration for and development and production of oil & gas and in estimating reserves, unexpected future capital expenditures, general economic conditions, oil and gas price volatility, the success of our risk management activities, competition, regulatory changes and other factors discussed in PXP’s filings with the Securities and Exchange Commission.

2

PXP

Business Profile

409 MMBOE proved reserves(1) 67.7 MBOEPD(2) 16 yr R/P

90% Oil reserves 77% Oil production 90% Wells operated

95% Average working interest

Offshore California

San Joaquin Valley

L.A. Basin

West Texas

Gulf of Mexico

17 MMBOE

392 MMBOE

(1) 2004 year-end proved reserves adjusted to reflect 1st QTR 2005 asset transactions. (2) Production is 2nd QTR 2005 average.

3

PXP

Value Creation Strategy

Focus on core geographic areas to maximize free cash flow

Allocate free cash flow to maximize per share growth

4

PXP

Excellent Reserve Growth

Reserve Replacement

All-in

Finding & Development Costs

10 Year (1) 3 Year 2004 10 Year (1) 3 Year 2004

All-in Organic PXP North American Industry Average(2)

584%

244%

654%

120%

975%

152% $4.99 $7.16 $7.23 $8.93 $6.97 $10.59

(1) Includes predecessor company results. (2) Source: Wachovia Securities.

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PXP

Production Growth

Production MBOEPD

125 100 75 50 25 0

2002 2003 2004 2005(E) 2006(E) 2007(E) 2008(E) 2009(E)

T-Ridge Potential $400

Operational CAPEX

($ Million)

T-Ridge requires a permit for development.

6

PXP

Future Reserve and Production Growth

Development/exploitation of core foundation assets

Targeted exploration

Selective acquisitions

7

PXP

Estimated Capital Allocation

($ Millions) 2005 2006

Development $225 $225

8

PXP

Development

Los Angeles Basin

Current Production: 16,000 BOEPD Production Growth: 8-10% 2005 Capital: $125 Million Reserves: 166 MMBOE R/P: 28 Yrs.

NET BOEPD

25,000 20,000 15,000 10,000 5,000 0

2003 2004 2005(E) 2006(E) 2007(E)

BSI Acquisition

Inglewood

Montebello et. al.

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PXP

Development

Inglewood Reserves

Reserves, MMBOE Capital, $MM

Proved Developed Proved Undeveloped Probable & Possible 2006-2010

Inglewood Shallow

Vickers-Rindge 54 23 2 130-150

Deep Inglewood

Rubel 5 30-50

Moynier 3 3 17 60-80

Bradna 30 10-50

Sentous 4 1 19 100-150

Subtotal 7 4 71 200-330

Total 61 27 73 330-480

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PXP

Development

San Joaquin Valley

230-235 wells planned in 2005

2,000 estimated future well locations in San Joaquin Valley and Arroyo Grande asset areas

2005 capital $80 million

26.7 net MBOEPD 1st half 2005

195 MMBOE proved reserves, 20 year R/P

Additional 110 MMBOE unproven potential

NORTH BELRIDGE

LOST HILLS

SOUTH BELRIDGE

CYMRIC

McKITTRICK

ASPHALTO

RR GAP

ELK HILLS

Buena Vista

PXP Fee Land PXP Leased Land PXP Royalty

PXP Surface or Mineral Fee

11

PXP

Development

Point Arguello/Rocky Point

188 Million bbls produced to date

Currently 9,000 gross/4,000 net BOPD

C-14 re-drilled to higher position with more pay exposure

4th Qtr 2005 production start

Planned Rocky Pt. Wells

Rocky Pt. Structure

Platform Hidalgo

Platform Harvest

Platform Hermosa

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PXP

Development

Point Pedernales Field—Infill Drilling

74 million BOE produced to date Currently 9,000 gross/7,500 net BOEPD 3-D seismic newly reprocessed, last drilling 1997 Drilling rig on the platform used for workovers

Four locations available for 2006 drilling

PXP 100% working interest

Two to three months drilling time

$4 - $6 million average well cost

Offset wells produce 1,000-3,500 BOEPD

INFILL LOCATIONS

Wells With Cumulative Production over 4MMBO

T-Ridge Prospect Area

California

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PXP

Estimated Capital Allocation

($ Millions) 2005 2006

Development $225 $225

Exploitation $75 $75

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PXP

Exploitation - T-Ridge Opportunity

Offshore California

Pt. Pedernales Unit

Proposed Project Well

California

T-Ridge Prospect Area

Reserve Potential: 150 MMBOE

Legend

Producing/Developable

Permits Required for Development

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PXP

Exploitation

South Louisiana

Assessing overall damage and repair time from Katrina Queen Bess #1:

Shut in for Katrina

15 MMCFD gross

PXP working interest 50%

Queen Bess #2:

Logged approx. 85’ net pay

15 MMCFD+ gross, expected when hurricane damage repaired

PXP working interest 75%

Queen Bess #3:

Drill after Queen Bess #2

Rig Available

PXP working interest 50%

6 Breton Sound prospects remain for 2005-2006 drilling 2005 capital $50-60 million

New Orleans

Breton Sound

Queen Bess Island

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PXP

Estimated Capital Allocation

($ Millions) 2005 2006

Development $225 $225

Exploitation $75 $75

Exploration $100 $90

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PXP

Exploration

Project Area Operator Timing Net Reserve Potential (MMBOE) Estimated Net Exploration Capital $MM

GOM Deepwater 150+ $50-100

Bigfoot Chevron Drilling

Pathfinder Shell Drilling

Caesar Kerr-McGee 4th Qtr 2005

Winter Park Chevron 2006

Eagle 2007 150+ $50-100

Total Potential 300+ $100-200

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PXP

Exploration—L/M Miocene Trend

Deepwater Gulf of Mexico

Houston

Mad Dog Neptune Atlantis Puma Aspen K-2 K-2 North Shenzi Tahiti Tonga Sturgis

2.3 BBO Recoverable Discovered to Date

New Orleans

1500’

3000’

4500’

6000’

Winter Park

Caesar

Pathfinder

Bigfoot

1500’ 3000’

4500’ 6000’

PXP Prospects Industry Discoveries

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PXP

Exploration – Caesar Prospect

Green Canyon 683

M14 Sand M15 Sand

M18 Sand

M21A Sand

M21B Sand

208’ NET PAY

Type Log

Tahiti Field

GC 640 #1

69’ NET PAY

192’ NET PAY

“CAESAR”

“TAHITI”

“TONGA”

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M21A Sand Structure Map

PXP

Exploration – Eagle Opportunity

Green River Basin, Wyoming

Large Basin Centered type Rockies gas prospect

PXP 50,000 net acres

PXP operator

75% working interest

Green River Basin Jonah-Pinedale analog Pressure chimney and gas tested by older vintage wells Permitting in progress, likely 2007 drill

Eagle Prospect

Pinedale Field

Jonah Field

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PXP

Exploration – Eagle Opportunity

Green River Basin, Wyoming

WYOMING

Sublette County

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PXP

Exploration – Eagle Opportunity

Green River Basin, Wyoming

Shell Govt. 43-18

EAGLE PROSPECT

Proposed Location

Pinedale Field 300 Wells Drilled Cum 261 BCFG + 2.1MMBO

EUR 9.2 TCFG

Jonah Field 600 Wells Drilled Cum 1.4 TCFG + 13.8MMBO

EUR 8.5 TCFG

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PXP

Exploration – Eagle Opportunity Green River Basin, Wyoming

Shell

Govt. 43-18

LANCE

4,870 MD

2,993

238’ Net Gas Pay

MESAVERDE

6,180 MD

1,383

141’ Net Gas Pay

DST’s –

Open hole

1970

Shell Discovery

Proposed Location

Structure – Lance Formation

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PXP

Exploration – Eagle Opportunity

Jonah Field - Strat Section

Elm Federal GOVT 23-22 TVD

8,000 8,500 9,000

9,500

TD 9,800

Top Lance

Gross Thickness 1,832’ Net Pay 463’ 25% N:G

Gross Thickness 3,010’ Net Pay 602’ 20% N:G

Increase in gross interval thickness to the East

Cabrito GOVT 15-13 TVD

10,000 10,500 11,000 11,500 12,000 12,500 TD 12,800

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PXP

Exploration – Eagle Opportunity

Strat Section

Shell GOVT 43-18

5,000 5,500 6,000 TD 10,650

Top Lance

Gross Thickness 1,310’ Net Pay 239’ 18% N:G

ESTIMATED Gross Thickness 2,000’ Net Pay 200’ to 600’ 10% to 30% N:G

Proposed PXP Eagle 1

Increase in gross interval thickness to the East

5,500 6,000 6,500 7,000

7200

7300

TD 12,000

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PXP

Estimated Capital Allocation

($ Millions) 2005 2006

Development $225 $225 Exploitation $75 $75 Exploration $100 $90

Acquisitions/Real Estate $170 $10

Total $570 $400

27

PXP

Financial Drivers

Attractive all-in cost structure

Improved oil price exposure resulting in higher realizations and margins

Substantial free cash flow at current commodity prices

28

PXP

Attractive All-in Cost Structure $ Per Barrel Oil Equivalent $30 $25 $20 $15 $10 $5 $0

PXD XTO EOG CHK PXP NBL VPI NFX PPP

PXP

2004 Cash Costs 2000-2004 F&D Costs Organic

Source: Wachovia Securities

Cash Cost: LOE, G&A, Interest, Taxes

29

PXP

2006 Estimated Cash Operating Margin Sensitivity

2005 YTD(1) 2006(E)(2)

Per BOE

Cash Operating Margin

Derivative Costs Production Expense Differential

Oil (WTI)/Gas (HH) $51/6.50 $51/6.50 $60/8 $80/10

Cash Operating Margin = price net of differentials and derivative cash costs minus production expenses.

(1) YTD Actual 6/30/05. (2) Applies 2005 mid-point expense and differential guidance. Applies mid-point 2006 production guidance.

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PXP

2006 & 2007 Cumulative Estimated Cash Flow

2,000 1,600 1,200 800 400 0

20 30 40 50 60 70 80

Operating Cash Flow ($ Millions) $ Oil Prices

Prior Put/Collars Current Put/Collars CAPEX

Operating cash flow is a non-GAAP measure. See the last page of this presentation for an explanation and reconciliation of non-GAAP financial measures; Applies 2005 mid-point expense and differential guidance; Applies mid-point 2006 production guidance; Assumes 2007 production flat to 2006.

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PXP

Cash Flow Allocation Opportunities

Disciplined capital expenditure program Selective acquisitions Build liquidity Return to shareholders

32

PXP

Value Creation Strategy

Focus on core geographic areas to maximize free cash flow

Allocate free cash flow to maximize per share growth

33

PXP

Reconciliation of Non-GAAP to GAAP Measures

Cumulative 2006 and 2007 Projected Operating Cash Flow: Reconciliation of Non-GAAP to GAAP Measure

The following is a reconciliation of cumulative 2006 and 2007 projected operating cash flow (non-GAAP) to net cash provided by operating activities (GAAP). 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.

NYMEX WTI/Henry Hub Gas

($Millions) $20/4 $30/5 $40/6 $50/7 $60/8 $70/9 $80/10

With Prior Put/Collars

Operating Cash Flow (Non-GAAP) $650 $770 $890 $1,060 $1,350 $1,580 $1,860

Reclass collar settlements (40) - 42 122 202 283 363

to financing

Capitalized interest 8 8 8 8 8 8 8

Change in operating assets & - - - - - - -

Liabilities

Net Cash Provided by $618 $778 $940 $1,190 $1,560 $1,871 $2,231

Operating Activities (GAAP)

With Current Put/Collars

Operating Cash Flow (Non-GAAP) $1,140 $1,150 $1,160 $1,120 $1,250 $1,480 $1,750

Reclass collar settlements (40) - 42 122 202 283 363

to financing

Capitalized interest 8 8 8 8 8 8 8

Change in operating assets & - - - - - - -

liabilities

Net Cash Provided by $1,108 $1,158 $1,210 $1,250 $1,460 $1,771 $2,121

Operating Activities (GAAP)

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.

Assumptions: Applies 2005 mid-point expense and differential guidance; Applies mid-point 2006 production guidance; Assumes 2007 production flat to 2006.

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PXP

PXP

Lehman Brothers

2005 CEO Energy/Power Conference

September 2005

35

N Y S E : P X P w w w . p l a i n s x p . c o m