e425
 

Filed by Pioneer Natural Resources Company
pursuant to Rule 425 under the Securities Act of 1933
and deemed filed pursuant to Rule 14a-12
of the Securities Exchange Act of 1934
Subject Company: Evergreen Resources, Inc.
Commission File No. 1-13171

     On May 4, 2004, Pioneer Natural Resources Company (“Pioneer”) and Evergreen Resources, Inc. (“Evergreen”) announced the proposed merger of a wholly-owned subsidiary of Pioneer with and into Evergreen. Set forth below are slides presented at an analyst conference on May 7, 2004 and May 8, 2004.

 

 

Executive Overview Scott Sheffield Chairman, President and Chief Executive Officer

 

Forward Looking Statements Except for historical information contained herein, the statements in this Presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements, and the business prospects of Pioneer Natural Resources Company, are subject to a number of risks and uncertainties which may cause the Company's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of oil and gas prices, product supply and demand, competition, government regulation or action, foreign currency valuation changes, foreign government tax and regulation changes, litigation, the costs and results of drilling and operations, Pioneer's ability to replace reserves, implement its business plans or complete its development projects as scheduled, access to and cost of capital, uncertainties about estimates of reserves, quality of technical data, environmental and weather risks, acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. This Presentation does not constitute an offer of any securities for sale.

 

Vision Long-lived asset anchor in North America Sustainable long-term growth Ability to endure cycles High-impact upside potential Balanced portfolio of assets Balanced risk/reward profile Balanced geographically Abundance of opportunities Talented team and empowered culture Solid strategies and ability to execute The ideal E&P company

 

Pioneer Model Long-lived foundation assets Lower maintenance capital Superior free cash flow Balanced portfolio of opportunities Low-risk to higher-risk Near-term to long-term Domestic to international Investment decisions driven by value creation potential Talented team with competitive incentives Goal: Above average growth in net asset value per share

 

Pioneer Strategy Moderate low-risk growth from onshore foundation assets Deploy portion of free cash flow to high-impact high- return exploration and acquisitions Develop exploration successes with portion of free cash flow Harvest portion of cash flow from high-return exploration successes to rebalance portfolio Acquire new foundation assets adding low-risk drilling opportunities Expand position in existing core areas Expand exploration portfolio Repurchase shares, buying reserves at ~$1.10 per Mcfe

 

Example: Evergreen Merger Best long-lived gas asset onshore North America Provides low-risk opportunities to balance Pioneer's drilling program Compatible technical expertise and cultures Adds unconventional gas (CBM) expertise that can be leveraged in other plays Leverages expertise with: Statistical plays Fracture stimulation technology Lower-pressure gas gathering systems Substantial Rockies acreage position in key growth basins

 

Reloads Lower-Risk Onshore Base Argentina Gabon Tunisia Alaska United States Canada South Africa Pioneer Operations Evergreen Operations West Panhandle Spraberry Uintah Piceance Raton Pawnee Hugoton Pro Forma Proved Reserves 12/31/03 6.2 Tcfe or 1,038 Mmboe Pro forma reserves represent 12/31/03 reported volumes and do not include future positive reserve adjustments to conform the treatment of field fuel on a combined basis. 2% 12% 86% North America Africa Argentina 59% 41% Natural gas Liquids

 

2004 2007 2010 Base 121 120 122 116 113 111 109 New Base 0 25 30 35 42 50 60 Offsh/Intl 88 90 88 91 95 98 100 Exploration 8 30 25 60 2004 2007 2010 Base 121 120 122 116 113 111 109 New Base 0 25 30 35 42 50 60 Offsh/Intl 88 90 88 91 95 98 100 Exploration 8 30 25 60 Lower-risk onshore base Medium-risk offshore & international w/commercialization Higher-risk exploration Rockies added to low-risk onshore base Over time, production profile shifts to more risky projects Rebalances production profile adding low-risk growth to base Reloads Lower-Risk Onshore Base (Mboepd)

 

Large low-risk drilling inventory in Raton Basin Less than 50% drilled ~1,500 undrilled locations Over 360,000 net acres Only $30 to $40 million capital expenditures per year needed to replace production Upside value in Piceance and Uintah basins and in Canada 220,000 net acres in Piceance and Uintah 100,000 net acres in Canada 5 year average reserve replacement over 800% Industry leader in F&D cost (source: Wachovia) 5 year average F&D - $2.96 per Boe 5 year average organic F&D - $1.98 per Boe Industry's best recycle ratio (cash-on-cash return) 3 year average ? 4.4X (source: Wachovia) Future Growth Potential

 

PXD PF XTO APC APA EOG BR NBL KMG UCL ECA DVN R/P ratio 15.8 14.8 13.1 13.1 12.6 12.5 12.3 10.4 10.4 10.1 9.2 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 * As of 12/31/03, pro forma for acquisitions and divestitures. Peer group data compiled by J.P. Morgan Securities Inc. Total Reserves/Production Ratio*

 

Building a Better Business Strong culture Empowered employees Effective open communication Team-oriented Responsive Encourages innovation Talented, motivated team Portfolio management process Company-wide, consistent evaluation process Peer reviews Post-audits Focus on efficiencies, cost control Technical expertise Field automation Efficiencies of scale Clear direction Integrity of the numbers Successful efforts accounting Third party reserve audit

 

Onshore Development U.S. operations concentrated in five core areas Well positioned to benefit from economic recovery in Argentina New opportunities to pursue in Canada Argentina United States Canada West Panhandle Spraberry Uintah Piceance Raton Pawnee Hugoton

 

Commercialization Gabon Tunisia Alaska South Africa Gulf of Mexico

 

Impact Exploration West Africa North Africa Gulf of Mexico Alaska

 

Financial Overview Tim Dove Executive Vice President and Chief Financial Officer

 

*Assumes 09/30/04 Closing 2002 2003 2004E 2005E Oil 41.436 56.48 70 70 Range 0 0 3 11 Production from Evergreen assets expected to double by 2008 Evergreen Production Free Cash Flow and Production Growth ~$1.2-$1.3B of excess flow above base capital expenditures in 2005/2006 Low-risk growth from onshore assets balanced by high-impact opportunities in Alaska, Gulf of Mexico and Africa Targeting 10% CAGR for 2004-2008

 

Prudent Capital Allocation First Level NAV/NPV accretion at discount rates of 8% to 10% IRR/DROI Cash flow accretion Upside/growth potential Second Level Production timing and impact Reserve replacement and booking timing Finding cost/BOE Key Project Metrics (all per share if applicable) All metrics calculated on an after-tax basis

 

Prudent Capital Allocation After "peer review", all possible projects are submitted in the annual budget process All projects are risked and sized on a consistent basis Various price decks and reserve cases are analyzed Reserve Cases: P90, P50, Mean, P10 Price Cases: $22/$3.50, $25-$27/$4-$4.50 & strip Projects ranked by risked DROI Different thresholds for different risks All projects are rolled up together in corporate portfolio model; optimization assessed in relation to all corporate metrics, both short and long term Critical Processes

 

Prudent Capital Allocation Projects submitted during the year are considered in light of the existing portfolio Do current commodity prices and cash flow justify a budget increase? Are there existing projects ranking below the new entrant that it should replace? Individual exploration wells are evaluated based on: Quality of the prospect Robustness of the "success case" economics based on P50 reserves (not mean reserves) Upside Dry hole exposure Critical Processes

 

Prudent Capital Allocation Stock repurchases Requires continuous update of internal NAV estimate Considered as an alternative use of capital that must meet internal thresholds Hedging is used to: Lock in excess returns Mitigate downside risk Insure balance sheet targets are met Adequately assess above-ground risk in all areas of operations Working interests in exploration wells are optimized Accountability is critical "Look-back" analysis - technical and economic "Change-in-Value" analysis Important Considerations

 

Balanced Capital Allocation Development Drilling Commercialization Seismic/G&G G&A/Acreage Expl. Drilling - Low Risk Expl. Drilling - High Risk East 285.896 76.299 150 47.567 106.615 Development Drilling Commercialization Seismic/G&G G&A/Acreage Expl. Drilling - Low Risk Expl. Drilling - High Risk East 345 138 150 77 107 North America Africa Argentina Other International East 512 51.503 99.161 27.34 North America Africa Argentina Other International East 661.79 51.5 99.161 27.34 Development Drilling 2004E Pioneer Standalone * * Excludes acquisition capital Commercialization Seismic / G&G G&A / Acreage Expl. Drilling - Low Risk Expl. Drilling - High Risk 2004E Pioneer with Evergreen * Development Drilling Commercialization Seismic / G&G G&A / Acreage Expl. Drilling - Low Risk Expl. Drilling - High Risk North America Africa Argentina Other International North America Argentina Other International Africa

 

Balance Sheet Management Debt reduction will be accomplished by utilizing free cash flow Target debt to book capitalization of approximately 45% by year-end 2004 Target debt to book capitalization of 40% or lower by year-end 2005 Goal is mid-Investment Grade credit rating Aggressive hedging program for both Pioneer's and Evergreen's 2004 and 2005 production has been implemented to achieve debt reduction target

 

Quality Assurance Andrew Quarles Manager Planning

 

Purpose of Quality Assurance Generate superior returns by managing and exploiting project-based technical risk and uncertainty Specifically: Accurate and realistic project evaluations Integrity in the decision-making process Improving performance by learning Focuses on technical risk and uncertainty Non-systematic, non-financial, "non-hedgeable", diversifiable risk Includes both G&G and engineering, surface and subsurface parameters

 

Integrated geoscience-engineering-commercial teams + Locally controlled project generation and execution + Systematic evaluation and risking + Centrally controlled portfolio management + Accountability = Deliver on expectations, create value Quality Assurance Processes Formula for Success

 

Peer Review - G&G and Engineering Are assumptions reasonable? Can risks be mitigated? Post Audit & Full-Cycle Analysis Monitoring economic returns and project value drivers: Expected vs Actual Portfolio Modeling Which capital investments portfolios will maximize corporate value and achieve goals? Change in Value Analysis Monitor and explain changes in 2P volumes and values Quality Assurance What is Quality Assurance? Risk and Uncertainty Testing and analyzing assumptions Improving future decisions by comparing expected and actual results and increasing accountability Determining the optimal capital allocation in order to meet corporate goals Corporate Project

 

Peer Reviews Goals Describe and defend assumptions Reduce risk and uncertainty Formal presentation to peers Variety of decision types can be peer reviewed Reality checks Benefits Avoid costly mistakes based on an under or overestimation of risk and uncertainty Forum to thoroughly review technical details Knowledge sharing between groups, regions and disciplines

 

Post Audit/Full-Cycle Analysis The post audit/full-cycle analysis is designed to address four questions related to capital spending: What was expected to happen? What did happen? Why are outcomes different? Based on this information, what changes will be made? Full-cycle look backs: Do full-cycle economic returns match expectations? G&G and engineering post audits analyze value drivers to explain full-cycle look backs Benefits Learn by updating assumptions, decisions and operations at a project/program level Identifying and addressing trends at the corporate level Ability to track full-cycle vs. point forward decisions

 

Change in Value Report Measures and explains annual changes in 2P reserve volumes and value 2P value represents majority of corporate NAV Compare predicted and actual end-of-year values Price and foreign exchange rate normalized The effects of capital, production and acquisitions are incorporated Changes in 2P volumes and values must be due to: Results of capital spending Revisions of beginning of year estimates Benefits Provides a corporate and project perspective of where and how 2P value is being created Measures impact of revisions on value and volume Provides insight on how to update the reserve report

 

Portfolio Modeling Portfolio modeling is a process of analyzing strategy and capital allocation problems that: Ties capital allocation decisions directly to business strategy and corporate goals Forecasts performance given risk and uncertainty at an aggregate business level Answers "How do we get where we want to go?", not just "Where do these projects take us"?

 

Portfolio Management Process Portfolio of All Opportunities Existing and Potential Projects Acquisition/Divestures Corporate Constraints and Goals Operational & Financial Metrics INPUTS Feasibility: Do project combinations exist that meet all constraints? Optimization: Maximizing NPV and minimizing risk. Identify "Efficient Frontier" Output - "Portfolio" New combinations with different timing, working interest and mix of projects Confidence levels of meeting goals PORTFOLIO MODEL What happens if capital increased by 10%? How can the likelihood of reaching a goal be increased? Compare tradeoffs between portfolios SCENARIO ANALYSIS Communicate results Graphics that illustrate impact of different investment decisions Repeat process by changing available projects and/or constraints and Value is gained from learning and analysis, not from seeking "The Optimal Portfolio"

 

Quality Assurance Challenges Requires alignment of many factors Behavior and people Culture Leadership Tools and processes Implementation Requires significant investment (manpower, tools and time) Integrating G&G and engineering processes Applying probabilistic analysis throughout evaluation and decision making process These complexities create an opportunity for competitive advantage

 

Summary Pioneer is one of a few "stellar examples over the past couple of years...of objective, consistent project evaluation processes balanced and integrated portfolio management achievable, properly balanced goals and supporting incentives sound strategic decision-making and strong financial performance." -Peter Rose - Senior Partner, Rose & Associates, LLP Pioneer started these efforts in 1997 and is continuing to implement and advance these processes to ensure continued success

 

North America Onshore Danny Kellum Executive Vice President - Domestic Operations

 

U.S. Core Onshore Production* 4.6 Tcfe of proved reserves 75% of total company proved reserves 555 Mmcfepd of current production ~45% of total company production ~15% of 2004 discretionary cash flow to maintain production ~4,500 drilling locations in inventory ~99% operated *Pro forma for merger with EVG Texas Kansas Colorado Utah West Panhandle Spraberry Uintah Piceance Raton Pawnee Hugoton

 

U.S. Core Onshore Production* Concentrated position Premier long-lived fields Provides stable production and cash flow 2004 production estimate 32 Mmboe ~$680 million net operating cash flow in 2003 Control midstream Fully automated R/P ratio of 23 years Less capital required to maintain production Multi-year inventory of locations Average working interest > 90% Continue bolt-on acquisitions in core areas *Pro forma for merger with EVG Texas Kansas Colorado Utah West Panhandle Spraberry Uintah Piceance Raton Pawnee Hugoton

 

Operations Efficiency & Automation Largest SCADA automation system in the world Automated equipment control from remote locations TOWcs electronic production data reporting Leader in new technology and crude oil measurement techniques Field technician training program Awarded two jointly funded EOR studies with the DOE Fully Automated Fields: Spraberry West Panhandle Hugoton Pawnee Raton (by 12/04)

 

Gas Gathering & Compression Optimization Over 90% of Pioneer gas processed through Pioneer- owned or jointly operated plants Provides additional revenue through 3rd party gas processing Control gas flow from the wellhead to the tailgate of plant Compression optimization Improved drip recovery Pipeline modifications Fuel savings Optimizing manpower Minimize downtime Gas Plants Provide Gathering Efficiencies and Strong Competitive Advantage

 

2004 Domestic Development Capex* West Panhandle Spraberry Pawnee Hugoton Gulf Coast E. TX / N. LA Canyon East 57 52 34 6.5 16 8 6 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 $57 MM $52 MM $34 MM $7 MM $16 MM $8 MM $6 MM * Excludes Deepwater development of $75 MM and EVG assets 85% directed to four legacy fields

 

Spraberry Field Kansas Largest operator 3,700+ wells Working interest ~100% Proved reserves 12/31/03 (Mmboe) 334 Current production (Mboepd) 29 R/P (years) 32 Drilling inventory ~2,100 wells 2004 wells planned ~120 CAPEX $50 million per year Development cost of ~$3.50-$4.00 per boe Completed two acquisitions totaling $33 million over the past six months 1,000 Boepd 175 PUD locations Largest SCADA system in the world 4 rigs currently drilling, 2 rigs owned by Pioneer ~100% success rate Texas Spraberry

 

Spraberry Field Upside Acquisitions and Joint Ventures Tom Brown Acquisition Closed 12-30-03, $12.5 million 259 Wells 6 Mmboe, 372 Boepd 109 PUD Locations Merit Acquisition Closed 4-1-04, $20.7million 287 Wells 8.5 Mmboe, 556 Boepd 68 PUD Locations Evaluating additional acquisitions 130,000 acres of deep rights under Spraberry Waterflood Optimization - DOE Project

 

West Panhandle Field West Panhandle Field Pioneer operates 370 Brown Dolomite wells 230 Red Cave wells Working interest ~100% Proved reserves 12/31/03 (Bcfe) 467 Current production (Mmcfepd) ~127 R/P (years) 11 Drilling inventory 400+ wells 2004 wells planned ~100 3 rigs currently drilling CAPEX $50 million per year Company controls production, gathering and gas processing High associated NGL production

 

West Panhandle - Past Drilling Results Wells Incremental Rate Incremental Reserves Singles 70 167 Mcfpd 378 Mmcf Duals 77 298 Mcfpd 628 Mmcf Total/Average 147 236 Mcfpd 509 Mmcf 1999 - 2003 Horizontal Brown Dolomite Results 1999 - 2003 Horizontal Brown Dolomite Results MASTERSON A-14 SINGLE MASTERSON A-14 SINGLE BIVINS A-173 DUAL

 

West Panhandle Production Without Horizontal Drilling With Horizontal

 

Hugoton Field Pioneer operates 670 Chase wells in Hugoton Field 330 Council Grove wells in Panoma Field Working interest ~100% Proved reserves 12/31/03 (Bcfe) 614 Current production (Mmcfepd) ~84 R/P (years) 19 2004 wells planned 20 wells 1 rig currently drilling CAPEX <$10 million per year Company controls production, gathering and gas processing Hugoton Field

 

Hugoton & Panoma Fields Hugoton & Panoma Fields Hugoton & Panoma Fields CHASE (Hugoton) PANOMA (Council Grove) Panoma Hugoton Chase

 

Replacement well drilling reduces decline rate about 2%/yr Replacement Wells - 2004 Program #1 Chase Infill #3 Council Grove #2 Council Grove Replacement #2R

 

Possible Upside Vacuum operations field rules (approved) Changing the Hugoton and Panoma allowable formulas or eliminating proration (under discussion) Allowing Panoma infill (2nd well) 350 possible locations on Pioneer's acreage Combining Hugoton and Panoma fields to allow more pay exposure in existing wellbores Horizontal drilling potential Panoma Infill

 

Pioneer operates 45 Edwards Reef wells Working interest ~100% Proved reserves 12/31/03 (Bcfe) 100 Current production (Mmcfepd) ~33 R/P (years) 8 Drilling inventory 30+ wells 2004 wells planned 10-15 wells 1 rig currently drilling CAPEX ~$35 million per year Company controls production, gathering and gas processing Significant third party gas revenues Pawnee Field Pawnee Field

 

Rockies Gas Fields Raton, Piceance and Uintah fields Operated Working Interest 75-100% Proved Reserves 12/31/03 (Tcfe) 1.5 Current Production (Mmcfepd) 139 R/P (Years) 32 Drilling Inventory +1,500 wells 2004 Wells Planned ~250 Company controls production, gathering and gas processing in Raton field Gas receives Mid-Continent differentials Colorado Utah Uintah Piceance Raton

 

Evergreen Integration Plan Estimated closing September 2004 May - September Management group joint planning Functional group task force interaction Cultural exchange Operations synergies High volume activities SCADA technology Volume buying power Service company leverage Cross utilization of manpower

 

Forward Operations Plans EVG controls proprietary technologies and equipment that have proven to be critical in the operation Two specialty-built rigs Three fleets of well service equipment Perform all cement work and custom designed fracture stimulation treatment Installed 550 miles of gathering lines and 80,000+ horsepower of compression Pioneer plans on continuing EVG's operations model as it has a proven track record of success Evaluating Raton acceleration Increasing from 200 to ~400 wells per year Capital reallocation Personnel/Services

 

Rockies Overview Mark Sexton Chairman, President & CEO - Evergreen Resources

 

Conventional Gas vs. CBM Production Drilling Conventional Gas CBM 500 to 15,000 feet 500 to 5,000 feet Usually brine; rates may increase during production life, water is typically reinjected Rates typically decrease during production life, numerous options for disposal; water may be usable at surface Water Production Fewer stages required More stages required Compression Initially, 1 to 2 wells per section, but density may be increased Well Drilling Pattern Production Profile Gas reserves and production are closely tied to initial pressure Gas adsorbed onto the coal and produced when pressure decreased Reservoir Gas Quality Gas typically associated with NGLs: ~ 80% methane Gas typically dry: ~ 99%+ methane, H2S not present Gas Production Gas can be shut-in and reactivated with little problems CBM well may need dewatering reinstated if not continually produced 4 to 8 wells per section Production Mechanism Reservoir pressure maintenance Reservoir desorption and dewatering

 

2000 2002 2004 2006 2008 2010 East 6.8 7.8 8.2 8.5 9.1 9.9 West 30.6 38.6 34.6 31.6 North 45.9 46.9 45 43.9 Source: Energy Information Administration, Office of Integrated Analysis and Forecasting (as of 1999) Source: Cambridge Energy Research Associates (Updated February 2004) U.S. Conventional vs. Unconventional Gas Resource Potential (Tcf) Coal Bed Methane As % of U.S. Gas Production

 

U.S. Coal Bed Methane Resources Western Washington 24 Tcf Wind River 6 Tcf Greater Green River 314 Tcf Uintah 10 Tcf Piceance 99 Tcf San Juan Fruitland Coal - 50 Tcf Menefee Coal - 34 Tcf Powder River 39 Tcf Raton Basin 10 Tcf Illinois 21 Tcf Northern Appalachian 61 Tcf Warrior Alabama 20 Tcf Central Appalachian 5 Tcf Greater Forest City Cherokee/Arkoma Basins 11 Tcf Source: GTI/ICF EVG Piceance/Uintah EVG Raton

 

Expected U.S. CBM Production San Juan 2,600 2.70 2.50 2.40 2.30 2.20 2.00 1.75 Powder River 700/1,500 0.35 0.89 0.95 1.00 1.05 1.30 1.50 Raton 1,500 0.10 0.20 0.23 0.27 0.30 0.35 0.40 Uintah 3,500 0.20 0.23 0.27 0.31 0.35 0.40 0.55 Black Warrior 1,800 0.31 0.31 0.31 0.31 0.31 0.29 0.25 Others (a) - 0.10 0.20 0.25 0.30 0.35 0.50 0.75 Subtotal 3.76 4.33 4.41 4.49 4.56 4.84 5.20 Alaska - - - - - - 0.01 0.05 Total U.S. 3.76 4.33 4.41 4.49 4.56 4.85 5.25 % of Total U.S. Gas Production 6.8% 7.8% 8.0% 8.2% 8.3% 8.9% 9.9% Average Well Depth (feet) 2000 2002 2003 2004 2005 2007 2010 Source: Cambridge Energy Research Associates (Updated February 2004) (a) Includes Arkoma, Appalachian, Cherokee, Forest City, Hanna and Illinois Basins. Capacity Outlook (Bcf per day)

 

EVG Acreage Position (thousands of acres) Raton 224 205 189 161 413 367 Piceance/Uintah 53 48 192 176 245 223 Canada 87 45 71 60 159 105 Developed Undeveloped Total Gross Net Gross Net Gross Net

 

Raton Basin Working Interest 75% - 100% Operator EVG Proved Reserves 12/31/03 (Bcfe) 1,393 % PUD 38% % Gas 100% Current Production (Mmcfepd) 133 R/P (Years) 31 Net Developed Acreage 205 K Net Undeveloped Acreage 161 K Total Net Acreage 367 K Vermejo-Trinidad Contact Spanish Peak COSTILLA CO. LAS ANIMAS CO. LAS ANIMAS CO. HUERFANO CO. Cucharas River Apishapa River Canadian River Vermejo River Purgatoire River WALSENBURG TRINIDAD SANGRE DE CRISTO MOUNTAINS 6 0 0 0 6 0 0 0 0 0 0 6 0 0 0 6 6 0 0 0 0 0 0 6 6 0 0 0 0 0 0 7 0 0 0 7 0 0 5 6 0 0 5 6 6 5 0 0 0 0 5 6 6 5 0 0 0 0 5 7 7 5 0 0 APISHAPA ARCH Raton

 

Raton Basin Geology Multiple intervals developed in new wells and existing wells through state-of-the-art recompletions The coals and tight sands of the Raton and Vermejo formations are primary objectives Extensive in-fill drilling opportunities in current gas price environment ($4.00/Mcf or greater) Vermejo coals: development, extensions & infill drilling (~1,000 locations) Raton coals: twin wells (~400 locations) Opportunities in deep fractured shales and Raton sands

 

Raton Basin Well Profile 0 300 Mcfpd Time (years) 30 Approximately 45% of reserves are produced in first 5 years Evergreen's historical drilling success rate is 99% Oldest well in area is 9 years old and has produced 55% of estimated ultimate reserves Water Methane 6-8% annual decline Remedial Fracture Stimulation(s)

 

Piceance & Uintah Basins Average Working Interest 84% Operator EVG, et al Proved Reserves 12/31/03 (Bcfe) 65 % PUD 49% % Gas 94% Daily Production Since Acquisition (Mmcfepd) 6 R/P (Years) 37 Net Developed Acreage 48 K Net Undeveloped Acreage 176 K Total Net Acreage 223 K Utah Colorado

 

Piceance & Uintah Opportunities Gas Coal Gas Lower Sego Cretaceous Jurassic Mancos B Rollins Cozzette Corcoran Castlegate Mowry Shale Tertiary MESOZOIC Ohio Creek Fluvial Coastal Paludal Iles Cameo Cedar Mountain Dakota Sands Williams Fork Buck Tongue Mancos Shale Utah Colorado Green River Frontier Morrison Buckhorn Sands Mancos Shale Anchor Tongue of Mancos Shale Mesa Verde Group EOCENE Upper Sego Wasatch Blackhawk Development drilling Stepout drilling Infill drilling Exploration drilling Recompletions of existing zones New zone additions

 

Potential CBM Upside in Piceance/Uintah Douglas Creek Arch Mesa Verde Cameo Coals 15 feet to 30 feet net coal thicknesses < 1,500 feet drilling depths Active economic production pilot 250 possible locations (2 projects) 200 Bcf natural gas reserve potential Castlegate Field - Uintah Basin Remedial and recompletion potential (coiled tubing unit fracs) ~ 80 feet coal thicknesses with 400+ Scft/Ton gas content ~ 200 potential drilling locations (EVG-owned gathering system) Deepest pure CBM field in Rockies 0.5 Tcf natural gas reserve potential

 

Potential Upside in Piceance/Uintah (Cont.) Rulison Field Recompletion Potential - Piceance Basin Multi-zone potential in Wasatch formation Bypassed pay behind pipe in existing wellbores Coiled tubing unit conveyed fracture stimulation technology EVG-owned gas gathering system in place 100+ remedial candidates Mancos "B" Recompletion Potential Wellbores with 1970 vintage frac jobs exhibiting low EURs ~ 100 remedial candidates Gas gathering system in place Coiled tubing unit conveyed fracture stimulation technology Production uplift and reserve add potential

 

Southeast Alberta Existing Conventional Resource Average Working Interest 63% Operator EVG, et al Proved Reserves 12/31/03 (Bcfe) 37 % PUD 28% % Gas 88% Daily Production Since Acquisition (Mmcfepd) 11 R/P (Years) 11 Net Developed Acreage 45 K Net Undeveloped Acreage 60 K Total Acreage 105 K Cessford/Carbon

 

Gas Bearing Development drilling Stepout drilling Infill drilling Exploration drilling Recompletions of existing zones New zone additions Conventional & unconventional reservoirs Southeast Alberta - Geology and Opportunities

 

Southeast Alberta - CBM Potential EVG Plans for 2004 Mannville Coals - 50/50 JV on 50,000+ acres - Two 4-well pilot projects planned for 2004 - Recompletion opportunities in existing well bores Horseshoe Canyon Coals - 100% WI in 12,800 acres - 6 wells planned for 2004 - Recompletion opportunities in existing well bores EVG acreage adjacent to economic Encana & MJV (Quicksilver) Palliser Horseshoe Canyon CBM projects 244 wells producing Drilling depths of between 1,000 feet and 1,500 feet High rate nitrogen frac jobs Water-free production Several Mannville CBM pilot projects in dewatering phase

 

Uintah Dumas Forgan Campo Wind River Powder River Bighorn D-J San Juan Raton Piceance Greater Green River & Overthrust Anadarko CIG Trinidad Denver Rocky Mountain Producer Mid-Continent Marketer: More Gas Markets & Pricing Flexibility Marketing Pipeline Expansion: CIG to increase Campo pipeline capacity by ~ 100 Mmcfpd to ~ 390 Mmcfpd in 10/05

 

Raton Basin Development Jay Still

 

Vermejo Raton Coal Coal Well Twin Well Well Cost $ 400,000 $ 200,000 Reserves ~ 1.15 Bcf ~ 1.0 Bcf Finding Cost $0.35 / Mcf $0.20 / Mcf % of Remaining Locations ~ 60% ~ 40% $4.00 per Mcf Nymex Payout ~ 4.0 years ~ 4.0 years ROI > 6.5:1 > 8:1 Rate of Return > 40% > 50% $5.00 per Mcf Nymex Payout ~ 4.0 years ~ 4.0 years ROI > 8:1 > 10:1 Rate of Return > 50% > 60% Raton Basin Comparative Well Economics

 

Canadian Operations Chris Cheatwood Executive Vice President - Worldwide Exploration

 

Calgary Cessford / Carbon Alberta and British Columbia Working Interest ~90% Proved Reserves 12/31/03 (Bcfe) 145 Current Production (MMcfe/d) 58 R/P (Years) 8 Drilling Inventory >150 wells 2004 wells planned 96 Completed successful winter program Wells planned to evaluate CBM potential of properties Evergreen acquired in October 2003 Canadian Assets* *Pro forma for merger with EVG Lookout Butte Chinchaga Martin Creek Bashaw

 

Synergies with Evergreen Seriously considered divestiture prior to Evergreen merger Minor production & reserves at corporate level Royalty trusts paying premium for gas properties Evergreen acreage has excellent coal bed methane potential Immediate offsets to very profitable Horseshoe Canyon play Low risk extension of play with over 100 bcf potential Additional potential in Mannville coals in Bashaw area Near-term program to begin organic growth Plan to drill ~10 Horseshoe Canyon wells in 2004 Two 4-well Mannville pilots at Bashaw in 2004 Conventional exploration tests with Encana at Bashaw Growth goals for Canada division > 20,000 boepd and 50 mmboe reserves by year end 2006

 

Argentina Guimar Vaca Coca President - Pioneer Natural Resources Argentina

 

Argentina Productive Basins Austral Noroeste Neuquen Cuyo San Jorge Buenos Aires Tierra del Fuego (TDF)

 

Argentina Highlights Pioneer in 10+ years of business: Established a solid base of profitable oil/gas production Acquired and developed significant undeveloped acreage Added high potential portfolio of properties to fuel growth Hired quality professional personnel Political and economic crisis that started in late 2001 affected all business negatively. Although, the oil sector was hit hard, Pioneer has continued to be profitable. Current challenge is to turn crisis into a significant opportunity for further growth.

 

Political & Business Environment Evolution with President Kirchner (12 Months of Government) Free market exchange rate with no Central Bank intervention, 2.90:1. Bank accounts, deposits, etc., unrestricted. International money transactions performed without issue. Contracts for public utilities in process of renegotiation. Tax on crude exports increased to 25% (20.04%). Local crude sales at 80% of WTI for prices above $36/bbl and at 86% of WTI for prices below $36/bbl. Tax on gas exports 20% (not applicable to TDF). Local residue gas sales* denominated in pesos are beginning to be adjusted upward. Initial price increase started on May 11th. For sales to large consumers, prices will rise to $1.10 US/mcf by July of 2005. Expect large consumer gas prices to rise to $1.40 US/mcf by end of 2006. For sales to residential consumers, prices expected to rise to $1.40 US/mcf by the end of 2007. LPG export taxes increased from 5% to 20%. *Neuquen Basin equivalent

 

Argentina Oil Production * Estimated 2003 R/P ratio *

 

Argentina Gas Production * Estimated 2003 R/P ratio *

 

Energy Crisis Main factors that caused energy shortage: Abnormally low gas price frozen by government (wellhead price $.40 US/mcf compared to $3.50 US/mcf in Zeebruge/Europe and $5.50 US/mcf Henry Hub). Dry season in hydroelectric basins lowered water levels behind dams and hydropower generation declined. Abnormally low prices of electric power frozen by government ($8 US/Kwh). Low gas prices drove: Industries to switch from traditional fuel sources. Skyrocketing commercial gas consumption. Automobile owners to convert vehicles from gasoline to CNG (30,000 cars per month switched to CNG). Electric power generation facilities consuming fuel oils to quickly switch to gas.

 

Gas Production per Basin Neuquen Austral Noroeste San Jorge

 

Energy Crisis Problem summary Shortage of gas for winter peak consumption forecasted to be up to 530 Mmcfpd (11% shortfall). Shortage of hydropower forecasted to continue through 2004. Actions Incentives to reduce consumption by residential and commercial users. Imports of liquid fuels for power generation from Venezuela. Imports of gas from Bolivia (max. pipeline capacity 140 Mmcfpd). Reduction of gas exports to Chile and Uruguay (from total 700 Mmcfpd to 100- 250 Mmcfpd). Implement gas price increases and strong pressure from the government for producers to increase production. Future expansion of the hydropower system. Results Industrial and some power generation consumers with interruptible contracts will suffer shortages. Residential and commercial consumers should not. If government accelerates gas price increases, consumption growth rate should slow down and producers and transportation companies may accelerate investments to reduce the impact of the crisis.

 

2004 Business Summary

 

Argentina Productive Basins Austral Noroeste Neuquen Cuyo San Jorge Buenos Aires Tierra del Fuego (TDF)

 

Neuquen Acreage Position Acreage 1,065,210 Acres 27 Blocks 1993 1994 1998 1999 2001 2003 Acreage equivalent to 211 blocks in Gulf of Mexico

 

Austral Acreage Position Operator PAE / BP Operator Pioneer Acreage 715,065 Acres 7 Blocks Acreage equivalent to 143 blocks in Gulf of Mexico 1992 1993 1995 1994

 

Pioneer Argentina Production Growth 93 94 95 96 97 98 99 00 01 02 03 04 Tierra del Fuego 1.46 2.89 3.03 3.06 3.63 3.79 3.83 3.7 3.3 3.6 3.7 3.7 Neuquen 0 0.2 1.4 0.9 2.2 3.8 4.4 5.7 5.8 4.4 5.7 7.2 Strong growth after political & economic crisis 20% Compounded Annual Growth * * 2004 Budget

 

Capital Investment and Operating Cashflow 92 93 94 95 96 97 98 99 00 01 02 03 04 Capex 2.1 8 28 31 29 77 62.3 39 68.8 77.8 35.5 51.2 102.4 Acquisitions 46.6 14 69 0 1 0 12 38 0 15.5 0 1.8 0 Op. Cashflow 10.2 21.5 29.3 31.1 47.5 43.6 99.6 123.9 108.3 65.9 85.6 101.4 Investment Average $63MM Cumulative $810MM * * Budgeted Capex and CF Outlook @ WTI $30 US/bbl, Gas price: $0.65 US/mcf

 

Argentina Exploration Daniel Kokogian Vice President - Argentina Exploration and Development

 

Potential Gas Wells Guanaco Deep Ranquilco Ranquilco Norte Portezuelos Norte Portezuelos Oeste A. Campamento A.C. East A.C. West Dos Hermanas 20 - 40 15 - 25 20 - 30 5 - 10 10 - 20 15 - 35 25 - 50 5 - 10 5 - 10 Existing Fields Leads & Prospects Total 120 - 230

 

Potential Oil Wells Loma Pedregosa Area Divisadero - A. Quinchao Loma Potrillo Cerro Vagon A. Campamento Ojo de Agua EFO East La Calera 10 - 20 20 - 40 10 - 15 20 - 50 10 - 20 10 - 20 10 - 20 50 - 500 Existing Fields Leads & Prospects * in early stage of evaluation Total 140 - 685 *

 

Conclusions The country went through a severe crisis that caused problems and losses for investors but it is rebounding from the crisis. The government is restoring gas prices and has maintained a stable fiscal system (with the exception of export tax increases). As the crisis becomes more manageable, the strong demand for gas and energy for both domestic consumption and exports should encourage the government to attract more investments by improving fiscal terms. Declining domestic oil production combined with high international oil prices may be another strong incentive for fiscal improvements. Pioneer has demonstrated its ability to successfully manage its business through the worst part of the crisis and has significant projects in progress to grow, plus a large position of very prospective acreage, 85% covered with 3-D seismic to explore and develop new projects. Pioneer has a track record as a low-cost operator and is respected by the oil community for finding and developing hydrocarbons left behind by other large operators. Pioneer's quality people are prepared for strong future growth.

 

Thanks. . . . . . . .

 

Political & Business Environment Young Democracy, influential Peronist Party: Crisis of 2002 Currency devaluation: From 1:1 to 4:1 Bank accounts and debts denominated in dollars: frozen and "pesofied". Restrictions on money transfers to and from abroad. Strict controls by Central Bank. Contracts regulated. Public utilities "pesofied" and frozen. Private contracts "pesofied" and adjusted. New 20% tax on crude exports. Local crude market sales in pesos at negotiated exchange rate. Gas exports in US$, no taxes. Local sales in pesos, frozen. LPG exports, 5% tax. Local sales at 5%-10% below export parity.

 

Political and economic trends Strong reactivation of economy. High exports of commodities and excellent prices (Soy beans, corn, meat, oil). GDP increased 8.7 % in 2003. Forecast slow down to 7.4% for 2004 due to energy crisis, drop of soy bean prices and possible increase of US interest rates. In 2002 GDP contracted by 10.9%. Negotiations of debt with IMF proceeding reasonably well. Budget surplus 3+ times more than required by IMF. Next renegotiations in June and December 2004. Negotiation of debt with bond holders ($100 billion + $18 billion past due interest) slow and hard but possible to reach agreement. Popularity of President Kirchner after one year in office remains high at 73% approval (down from 84%). Government continues blaming others for Argentina problems (specially blaming oil companies for lack of investments to prevent energy crisis), to gain popularity and political power. Still has many unresolved problems such as high unemployment, poverty, security and criminal issues, etc. However, social unrest is low and controlled. President Kirchner approved sending troops to Haiti as signal of friendship with US.

 

Argentina Fiscal System Federal Taxes - Income Tax 35% - Value Added Tax 21% - Minimum Presumed Income Tax 1% - Tax on Bank Accounts Transactions 1.2% - Tax on Exports * Oil (Eff. rate 20%) 25% * Gas 20% * LPG (Eff. rate 16.7%) 20% Provincial Taxes - Production Tax 2% - Stamp Tax 1% Royalties 12% (Eff. rate on LPG 3%) Dadin Huincul Tax Benefits: Income Tax - Minim. Presumed Income Tax - Prod. Tax Exempted Royalty Oil 9.3% - Gas 10% Tierra del Fuego Tax Benefits: Income Tax - Minim. Presumed Income Tax Exempted Value Added Tax (Net effect is 21% Extra Revenue) Liberated Tax on Exports Exempted

 

Gulf of Mexico Production Jay Still Vice President - Gulf of Mexico Operations

 

Deepwater Team Independent spirit breeds independent thought Get it right the first time Always be in a position of influence - settle for nothing less "Better - Cheaper - Faster" should facilitate more opportunity Experience as "confidence lever to step outside the box" and "not do it the same as it may have been done before" Calculated risks are the only risks worth taking There are a lot more mice than elephants (and the mice multiply a heck of a lot faster) In any organization's "bottom-line", there is a message - "success" is the only message worth delivering Key "driver" of Pioneer's success

 

Canyon Express Virgo Marlin Neptune Pipeline Umbilical Subsea Well Canyon Express Pipeline Canyon Express Pipeline 2 x 12" Lines 71 mile 500 Mmcfpd PXD 23.5% Ram Powell Camden Hills Marathon Operated PXD 33.3% King's Peak BP Operated Aconcagua Total Fina Elf Operated PXD 37.5% Canyon Station MP 261 Joint subsea development of three deepwater GOM fields World's deepest production - based on water depth 500 Mmcfpd capacity (PXD owns 23.5%)

 

Canyon Express Subsea Architechture

 

Canyon Express Deepwater Firsts Deepest water depth development to date Multi-field, multi-party joint development through a common jointly developed Canyon Express pipeline Pioneered use of multi-phase subsea flow meters for production allocation and royalty payments Largest offshore methanol recovery units Pioneer's Role Technical team members in subsea architecture design and development Contract negotiations specialist and mediator between major oil companies Driving the geologic modeling, reservoir characterization, and field development Champion a "sense of urgency" to the field development

 

Falcon Corridor Operator with a 100% WI in the area 3,400' water depth Control 32 blocks Began producing March 15, 2003 Harrier, Tomahawk & Raptor satellite tie-backs to the Falcon Field manifold Currently producing 275 Mmcpfd from 3 wells Falcon wells over $260 million cumulative cash flow Q1 '04 Payout in March 2004 Harrier well over $50 million in cumulative cash flow through Q1 '04 Payout in May 2004 Set record for deepwater development 2004 Activity Tomahawk start-up June 2004 Raptor start-up June 2004 1-3 exploration wells 2004 Additional exploration planned

 

 

11162101-02 HARRIER DEVELOPMENT EAST BREAKS 759 #1 (SURFACE LOCATION - EAST BREAKS 758) WATER DEPTH: 4114 feet EXISTING FALCON DEVELOPMENT EAST BREAKS 579 WATER DEPTH: 3450 feet FALCON PLATFORM MUSTANG ISLAND A103 HARRIER DEVELOPMENT 10.75" FLOWLINE (32 MILES) PLET JUMPER PLET WUTA-F 10.75" HARRIER FLOWLINE (14.5 MILES) ELECTRO-HYDRAULIC UMBILICAL (13.45 MILES) WUTA-T FLYING LEAD JUMPER PLET METER FALCON MANIFOLD

 

 

Falcon Deepwater Firsts Fast-track deepwater development records (Discovery to 1st Prod) Falcon - 14* months (excluding arbitration time) Harrier - 12 months Tomahawk - 9 months Raptor - 8 months 5th longest subsea tie-back (47 miles) Largest number of subsea field tie-ins (4) Pioneer's Role 100% working interest, Operator & Project Developer Utilization of 3rd party capital to provide process infrastructure, minimize upfront capital & maximize project economics In-house development and implementation of Subsea System full-field, fully integrated production model to "fuel" IPT Facilities design (subsea wet gas meters / separation / compression) Flow assurance (water production / hydrate inhibitor req'ts) Completion design (tubular req'ts / frac-pack design & modeling) Commercial (deliverability projections to aid negotiations& marketing teams) Internally developed and trained field operations personnel

 

Devils Tower - Project Description Truss SPAR 5,610' Water Depth 2 Subsea Tiebacks 8 Dry Trees 2 Export Pipelines Oil: 60,000 BOPD Gas: 60 MMCFPD Mississippi Canyon 773 80 to 100 Mmboe 25% PXD WI, Dominion 75% (Op) PXD production expected to reach 12- 14,000 Boepd 8 wells drilled, six awaiting completion First production May 4, 2004

 

Devils Tower Installation

 

Triton/Goldfinger Development PXD 25% WI 3 well subsea tie back to Devils Tower Sanction mid-year 2004 1st oil expected late 2005 EUR range 20 - 30 MMboe

 

Devils Tower Deepwater Firsts Deepest Truss Spar development (5600' WD) Probably the most innovative, complex, and challenging EPIC contract and utilization of 3rd party capital (via PHA). Leading edge technology - unique "TRIPLE SMART" Triton completion Pioneer's Role In a Non-Operator role, equivalent, highly pro-active, "across-the-board" participation in the project development to that of the Operator "Equal visibility" to Operator in subsurface interpretation (G&G/reservoir) State-of-the-art geophysics (elastic impedance techniques) Leading edge 3D simulation (Eclipse-EnAble) In-house development and implementation of the only SPAR + Subsea System full- field, fully integrated production model to "drive" the project Facilities design (riser base gas lift vs. subsea well gas lift) Flow assurance (production profiles to guide hydrate & wax inhibitor req'ts) Completion design (frac-pack performance & commingled zone modeling) Well surveillance (pre / post-production nodal/pressure transient analysis) Pioneer's Deepwater Project Team (Houston) charged with subsea satellite field development (Triton, Goldfinger)

 

Ozona Deep Auger Ozona Deep - Deepwater GOM Garden Banks 515 32% working interest, Marathon 68% (Operator) ~350' net oil pay in two primary intervals 3,280' water depth Development well planned in 4th quarter 2004 Expecting first production in 2006 Tie back to Shell's Auger TLP Negotiating PHA

 

Domestic GOM Operations Devils Tower Reserve upside through better reservoir connectivity Sidetrack opportunities in undrilled fault blocks Triton/Goldfinger tie-backs Other exploration tie-backs Falcon Falcon corridor exploration tie-backs Harrier look-alikes Deeper horizons Canyon Express In-field exploration opportunities resulting from WesternGeco speculative Q broadband seismic data Optimization of sidetrack opportunities in undrilled fault blocks Better than expected performance due to system optimization Future utilization of pipeline system Deeper horizons Ozona Deep Deep exploration potential

 

Pioneer Commercialization Activities Bill Hannes Vice President - Engineering and Development

 

Pioneer - Commercialization Philosophy Our Roadmap to Success: Take the right People Who are highly skilled Experienced, with diversified backgrounds Competitive ... but exemplify personal & professional integrity With the right Attitude Who communicate openly - vertically, laterally and externally with partners & agencies Value cross-functional teamwork and planning - technical, commercial, legal & regulatory And are committed to Pioneer's success - today and over the "long-haul" Provide them a variety of Opportunities Diverse portfolio -- domestic & international, risk & reward, exploration & exploitation That are challenging to attack -- technically & commercially And that engage cooperative creativity In a conducive Environment That is financially and professionally rewarding Provides the necessary resources -- people, tools, financial And is supported by an engaged management With aligned Vision & Goals That provide clear strategies for growth Encourage applying appropriate technology And appropriate risk-taking t

 

Commercialization Activities Alaska Jurassic discovery in Oooguruk field Expanded acreage position in area Evaluating commercialization of oil resources North Africa Expanding Adam oil development Gas discovered on Anaguid and BEK blocks Evaluating gas markets, infrastructure and commercialization opportunities Gulf of Mexico Leveraging infrastructure in Falcon, Devils Tower and Canyon Express corridors Gabon Executing Olowi development South Africa Gas Negotiating gas contract and preparing development plans

 

Why Alaska? World class petroleum system North America Larger field-size opportunities than Lower 48 Improving regulatory environment Business opportunities opening for independents

 

Alaska Commercialization Strategy Goal: Reduce cost and increase efficiency to commercialize abundant resources on the North Slope Achieve a step change in North Slope cost structure Independent mindset Leverage existing infrastructure Challenge existing methods Bring in successful concepts from other basins Cooperation from contractors Decrease project cycle times

 

West Africa Olowi Project Overview Objectives Profitably develop oil resources discovered/appraised in Olowi Leverage GOM & South Africa shallow-water experience to expand producing base into West Africa Resource Base 30 - 50 Mmbbl gross recoverable in high-graded sweet spot 10-30 Mmbbl additional upside Shallow reservoir Shallow water Thin oil rim, high-quality sands On-trend with existing production 100% Pioneer working interest

 

Olowi Project Status Project Status Completed to date Appraisal & evaluation activities for internal approvals Renegotiation of PSC terms FEED studies for selected & alternative concepts Hired country manager Current activities Meetings with DGH - declaration of commerciality

 

Olowi Project Schedule Project Schedule Exclusive Exploitation Area (EEA)- June Development plan approval - August Bid evaluation, final sanction - September Contract awards - September & October Start development drilling - early-2006 First production - 2H2006 Future Potential Expand development 10 - 30 Mmbbl potential increment Explore Vandji 60 Mmbbl risked mean recoverable Exploit gas cap >1 Tcf in-place

 

South Coast Gas Project Overview Concept Hub development from FA platform PetroSA Offshore infrastructure available for South Coast Gas tie-in Tie-in Sable gas and nearby pools (30 - 100+ Bcf pools) Potential platform & subsea tiebacks Project Schedule Joint development strategies mid-year Project sanction year-end 1st Gas Available 2007 PetroSA's F-A Production Platform

 

South Coast Gas Commercial Strategy Scope Equalization of interests in reserves Negotiate balance of financial exposure with acceptable gas contract Market 200 Mmcfpd PetroSA GTL Plant Plant needs additional feedstock beyond 2007 Competition West Coast (Forest Oil ) & Kudu Field (Namibia) Results to date will not support pipeline to PetroSA's GTL plant LNG Expensive Greenfield project Timing Potential long-term solution Timing Agreement with PetroSA in principle on commercial terms - mid-year 2004 Target completion of negotiations by end of year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 year 2004 PetroSA's Mossel Bay Plant

 

The Field Water Depth = 100m Current EUR = 16-20 MMbbls Pioneer WI = 40%, PetroSA = 60% The Development 7 wells - 4 producers & 3 injectors SS tie-backs to the FPSO "Glas Dowr" Production/Operations First oil = Early August 2003 Current Production rate ~ 23,000 Bopd with Gas Injection ~ 80 Mmcfpd Gross Cumulative Production to date = >5Mmbo Average sales price to date ~ $32/bbl (last sale priced over $40/bbl) Sable Project Update Sable Project Update

 

Stable Country, Good Fiscal Terms In prolific oil and gas fairway (Ghadames Basin) Early Success PXD entered in 2001, acquired large low- cost land position (5 MM acres) Drilled 5 discoveries 3 oil (Adam, Hawa) on production (9,100 BPD gross), also gas zones 2 gas (Anaguid), evaluating development Large Potential Oil - expand beyond 4-way closure (multi- MMBO potential) Gas - plays extend across multiple blocks, multi-TCF potential 2004 Plans Drill 3-5 wells, delineate, development plans LIBYA ALGERIA BORJ EL KHADRA PXD - 40% Adam Concession PXD - 28% 12 km 0 6 EL BORMA 966 MMBOE HAWA DISCOVERY Adam Concession Hammouda Oued Zar 110 MMBO Anaguid PXD - 39% Tunisia - Early Success ADAM DISCOVERIES

 

Potential Tunisia Gas Development Resource Development Multi-Tcf, extensive area (multi-blocks) Partner operated (Anadarko - Anaguid, ENI - Adam/BEK) Tight sands, many wells, stimulations Infrastructure Use existing for early development, testing Significant expansion for larger projects New 300 km pipeline Markets Target local markets initially Tunisia is net gas importer (shortfall 100-200 Mmcfpd by 2006- 2010) Larger developments need exports Southern Europe - Transmed Pipeline Anaguid Discoveries

 

Commercialization Summary Alaska Commercialize huge resource with "independent" approach West Africa Olowi development, looking to expand in West Africa South Africa Sable producing, commercialize South Coast gas North Africa Adam developments and Hawa, looking to expand oil and gas opportunities Gulf of Mexico Continue to leverage Falcon, Devils Tower and Canyon Express infrastructure

 

Worldwide Exploration Overview Chris Cheatwood Executive Vice President - Worldwide Exploration

 

Pioneer Exploration: The Vision Grow Pioneer through exploration projects which in total generate full-cycle returns greater than those of other less-risky opportunities available to the company. Combine the technical abilities of a major company with the entrepreneurial drive of an independent.

 

Geoscience Team XM BP CP CTX other East 25 10 9 7 9 Other VP North America Alaska Canada Gulf of Mexico 25 Geoscientists VP International West Africa North Africa Argentina Geophysical Technology 17 Geoscientists VP Exploitation Onshore U.S. Gulf of Mexico International Argentina Canada Geoscience Technology 26 Geoscientists Corporate Geology 2 Geoscientists EVP Exploration Very experienced (>20 years) Wide ranging international experience Key skills: Petroleum systems, Seismic processing, Petrophysics Virtually no turnover Complementing experience with youth from college recruiting

 

Exploration Steps Choose the right basins and countries to explore Prolific petroleum system Stable politics and viable economics Select the right plays to focus efforts Successes are good enough to cover the dry holes Build a portfolio of prospects within the plays Need sufficient number of prospects Balance and diversity of portfolio Devise and execute an adequate drilling plan to test the play How many wells to properly test the play Partner to share risk and diversify Conduct lookbacks to learn and adjust plans Different or modified approach to improve results Get out of the play at the right point

 

Undiscovered Reserves in the U.S. Focus exploration efforts on basins with most remaining reserves - Deepwater Gulf - Alaska North Slope - Gulf Deep Shelf Source: MMS / USGS Undiscovered Reserves of Top 10 USA Basins 0 5 10 15 20 25 Offshore Gulf Onshore Gulf Coast Northern Alaska Offshore California Permian Basin Beaufort Shelf Anadarko Powder River Chukchi Sea San Joaquin Bboe

 

Prolific Resources Stable or Improving Politics Best Value Partner With Experts Priority Economics Politics Resources Criteria for Selecting New Ventures Low entry and F&D costs High impact Growing market Low currency risk Stable or improving Safety Environmental concerns Perceived financial risk Prolific hydrocarbon system Reserve growth Ability to partner Assets available Ability to enter quickly Expertise available Partners/Competitors

 

How Do We Quantify Risk? All elements that must work for oil & gas accumulation: Trap, Seal, Reservoir, Migration & Timing Typical Prospects: 20-30% Chance of Success DHI Prospects: 60+% Chance of Success The Risk Matrix Approach

 

How Do We Quantify Risk? Historical Success Rates

 

Reasonable ranges of: Area, Reservoir Volume & Recovery Prospect Size Uncertainty How Do We Quantify Uncertainty? Prospect Size Range & Historical FSD

 

How Do We Quantify Uncertainty? Global Field Size Distribution

 

How Do We Quantify Uncertainty? RISK UNCERTAINTY Prospect Risk and Uncertainty

 

5 Year Success Rate - All Exploration Wells 5 Year Success Rate - All Exploration Wells >P10 Success Rate 88 total wells 44 successes

 

5 Year Success Rate - High Impact Wells P50 Success Rate 44 total wells 19 successes P10 P50 P90 P100

 

5 Year Discovered Resource - All Wells 5 Year Discovered Resource - All Wells 3P Mean Resource Discovered Within 10% of 3P Predicted Mean

 

Learnings/Actions Based on Lookback General More exposure to larger reserve plays Deepwater subsalt Alaska impact prospects West Africa AVO/DHI prospects In-house processing to reduce risk and improve results GOM Shelf Take a break from drilling to reassess program risk and define steps to improve results Diversify portfolio with shallow, higher Pg prospects Increase Pg using 3-D AVO, geopressure prediction, velocity prediction, etc. After assessment drill select number of highgraded prospects Determine whether to continue GOM Deepwater Delivered what we predicted

 

Learnings/Actions Based on Lookback South Africa Discontinue exploration Gabon Accurately predicted reservoir depth Reservoir quality exceeded expectations Oil column within predrill range but near P90 Overall effect reduced both OOIP and recovery factors Tunisia Stay the course - Early results are very encouraging More drilling needed to assess the real potential

 

Potential Inventory Additions Deepwater 14 new blocks from March 2004 lease sale Devils Tower satellites Shelf Play 5 new blocks from March 2004 lease sale West & North Africa West Africa Project One (closing) North Africa Project One (under negotiation) Additional Ordovician, Silurian and Permian Prospects in Tunisia West Africa Project Two (under negotiation) West Africa Project Three (completing evaluation) Additional Kosmos Joint Venture Projects Alaska Oooguruk Unit Farmout Storms area - 8-10 leads identified Gwydyr Bay - 6-8 prospects (some drilled, but undeveloped) Caribou Prospect New Alaska Project One (under negotiation) New Alaska Project Two (being considered) New Alaska Project Three (June 2004)

 

0 50 100 150 200 250 300 350 550 500 450 400 QUAT. Mio. Plio- Pleist. Olig. Eoc. Paleo. CENOZOIC U. JUR. TRI. PERM. CARB. L. DEV. U. L. SIL. L. U. ORD. U. M. L. CAM. U. M. L. PALEOZOIC MESOZOIC PALEO. CRET. M. U. L. MISS. PENN. L. M. U. Neoc. L. U. L. M. U. LATE PRECAM. Alpine Cimmerian Hercynian Caledonian Assyntic Subd. & Ass. Spreading & Disassembly Spreading & Disass. Subduction & Assembly Pangaea reservoir seal source Ghadames Petroleum System TAGI SS Acacus SS Ordovician Regional Seal Reservoir Intervals Source Rocks Regionally extensive evaporites to cap the petroleum system Regionally continuous sandstones with excellent reservoir quality Thick sequence of marine shales with high organic content

 

Ghadames Basin Extent Paleozoic Basins Mesozoic Basins Egypt Libya Algeria Tunisia Sirte Ghadames Mesozoic Source Paleozoic Source Oil Field Gas Field Spain

 

Tunisia Activity Update

 

West Africa Exploration West Africa 1998-2003 • High potential - over 14 Bboe found • Sizable fields - up to 1 Bbbl; average field size over 100 Mbbl • Affordable risk - 1:3 success ratio Currently working six new projects - Three generated by Kosmos - Three generated by Pioneer Three projects are very high potential - Multiple prospects with DHI/AVO support - Higher Pg and less uncertainty - Estimated gross reserves > 3 BBO

 

Conclusion Pioneer has built an excellent multi-discipline exploration team The exploration team has delivered results very close to those predicted We have a disciplined approach to quantify risk and uncertainty We now have the ability to participate in higher- impact projects Expect even greater results in the near future

 

North America Exploration Tom Spalding Vice President - North American Exploration

 

Keys to Success People Team oriented, motivated, challenged Experienced (avg. 20+ years) Recruiting, training and mentoring new hires Process Integrated teams: geoscience, engineering, business development Standardized risking, sizing and peer review Opportunity database, portfolio management Technology Integrated interpretation Geophysical Technology support IT support best in industry Petroleum Systems Gulf of Mexico Alaska North Slope Canada Western Sedimentary Basin

 

North America Balanced Portfolio Alaska Short-term Production Gwydyr Bay, Caribou Long-term Reserves Oooguruk/ Tuuvaq Storms Project One Project Two Project Two Project Two Project Two Project Two Project Two Project Two Project Two Project Two Canada Short-term Production Peace River Arch Clastics Wabamun Carbonate Alberta CBM Gulf of Mexico Short-term Production Shallow shelf Deep shelf Deepwater producing satellites Long-term Reserves Deepwater subsalt

 

Deepwater GOM - Focus Areas PROSPECT NAME PXD WI; YEAR DRILLED DISCOVERY UNSUCCESSFUL UNDRILLED ACQUISITION OCS SALE 190 APPARENT HIGH BID FLATHEAD 33% MYRTLE BEACH 10% 2004 CUDA GC 978, WR 10 GC / WR Focus Area PALADIN 67%: 2005 MAVERICK 50% 2005 OZONA DEEP 32%: 2001 Appraisal: 2002 GB / KC Focus Area Falcon Corridor FALCON 100%: 2001 HARRIER 100%: 2003 RAPTOR 100% 2003 TOMAHAWK 100% 2003 TURNBERRY 40%: 2001 DEVILS TOWER 25%: 2000 TRITON 25%; 2002 JUNO 25%; 2004 THUNDER HAWK 12.5%; 2004 COBRA MC 757, 758 GOLDFINGER 25% 2003 Devils Tower Corridor CHEVELLE VIPER CAMDEN HILLS 33%: 2000 ACONCAGUA 37.5%; 1999 MONTE CRISTO 25%: 2000 VETTE MC 346, 390 NE MC Focus Area CARRERA MC 391, 392 TBIRD 37 Deepwater wells drilled to date 18 Exploration wells (10 discoveries) 8 Appraisal wells (7 successful) 11 Development wells (11 successful) Exploration success rate 55% Overall success rate 76%

 

Exploration Province Drilling History (1975-2000) Source: Meyer & Rains, 2001 Success rates for the deeper non-amplitude plays are 1 in 4 Subsalt and Fold plays yield large reserves (large traps) The largest fields in the GOM are being found last! Compressional Fold 87

 

GOM Shelf Exploration Louisiana New Orleans Texas Houston 70 GOM shelf exploration blocks, 31 prospects Test shallow gas potential in second half of 2004 (4-5 wells, avg. $3.0 million each, 10 to 20 Bcf each) Reprocessing 3-D in deep gas play Woodside partner, 50% WI Joint Prospects 100% Pioneer

 

CPF 1 -8,000' KUPARUK RIVER 2,500 MMBO ALPINE 430 MMBO ENDICOTT 630 MMBO TARN 71 MMBO MILNE POINT 404 MMBO POINT McINTYRE 560 MMBO PRUDHOE BAY 12,300 MMBO LISBURNE 182 MMBO NIAKUK 98 MMBO BOREALIS 70-100 MMBO W. BEACH 7 MMBO Gwydyr Bay 48 MMBO Hemi Springs Sandpiper 7 MMBO NORTHSTAR 176 MMBO Cascade Nuiqsut FIORD 70 MMBO Meltwater 52 MMBO Palm Extension 60 MMBO Nanuk 50 MMBO AURORA 6 0 MMBO MIDNIGHT SUN 20 MMBO R 3 E R 4 E R 5 E R 6 E R 7 E R 8 E R 9 E R 10 E R 11 E R 12 E R 13 E R 14 E R 15 E R 16 E R 17 E T 13 N T 14 N T 12 N T 11 N T 10 N T 9 N T 8 N T 7 N T 10 N T 9 N T 8 N T 7 N Cretaceous Rift Sequence (Kuparuk Fm., Kemik, Thomson Ss) Triassic Ivishak Fm. Miss. Endicott Gp. Dinkum Graben Colville High Colville High Kalubik Thetis T 11 N ARL Caribou Gwydyr Storms Oooguruk Proposed New 3-D Current 3-D Recommended PXD Acreage AMI Acreage Joint CP/PXD 3-D Acquisition Oooguruk/ Tuuvaq Gwydyr Bay Caribou Storms Alaska - Central North Slope

 

Caribou Project Leases awarded May 1 PXD 50% (Operator), CP 50% Interpreting WesternGeco OBC 3-D to confirm prospect, model reservoir... Drilling group working with BP for potential use of Point McIntyre pad (or drill from ice) Drill recommendation by mid-June 2004 1-2 wells drilled in winter 2004-2005

 

Gwydyr Bay Project Leases awarded May 1 PXD 100% (operator) Negotiations on adjacent acreage farmouts BP polling owners to license 3-D Confirm prospects on 3-D, model reservoirs Drilling evaluating pad options (ice, gravel) Development recommendation by July 2004 Lay gravel and drill 6-7 wells in summer 2005

 

Storms Project Update Leases awarded May 1 PXD 50%, CP 50% (operator) More than 130,000 gross acres New 3-D acquisition in 1-2Q 2005 Interpret 3-D and map leads Drill in winter 2005-2006

 

Tuuvaq Project Area Update 40% PXD, Kerr McGee (Op)/Armstrong 60% Multiple objectives in Sag, Nuiqsit, Ivishak, Brookian Drill one well in winter 2004-2005 Combined development synergy with Oooguruk, Tuuvaq and Nikaitchuq units

 

North America Activity Through 2005 Alaska 7-9 wells (through mid-2005) Gwydyr Bay, Caribou 3-D acquisition and 3-7 wells Tuuvaq (1 winter 2004-05) Storms (1-2 winter 2005-06) Project One (1-2 winter 05-06) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Project Two (2 winter 04-05) Canada 1-4 wells (winter 05-06) Peace River Arch Clastics Wabamun Carbonate Alberta CBM (2-3 pilots) Gulf of Mexico 5-12 wells (through 2005) Shallow shelf (4-5 2004) Deep shelf (0-4 2005) Deepwater producing satellites (1-3) 3-5 wells (through 2005) Deepwater subsalt

 

Legal Information

     This filing contains forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995, particularly those statements regarding the effects of the proposed merger and those preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” or similar expressions. Forward-looking statements relating to expectations about future results or events are based upon information available to Pioneer and Evergreen as of today’s date, and neither Pioneer nor Evergreen assumes any obligations to update any of these statements. The forward-looking statements are not guarantees of the future performance of Pioneer, Evergreen or the combined company, and actual results may vary materially from the results and expectations discussed. For instance, although Pioneer and Evergreen have signed an agreement for a subsidiary of Pioneer to merge with Evergreen, there is no assurance that they will complete the proposed merger. The merger agreement will terminate if the companies do not receive necessary approval of each of Pioneer’s and Evergreen’s stockholders or government approvals or fail to satisfy conditions to closing. Additional risks and uncertainties related to the proposed merger include, but are not limited to, conditions in the financial markets relevant to the proposed merger, the successful integration of Evergreen into Pioneer’s business, and each company’s ability to compete in the highly competitive oil and gas exploration and production industry. The revenues, earnings and business prospects of Pioneer and the combined company and their ability to achieve planned business objectives will be subject to a number of risks and uncertainties. These risks and uncertainties include, among other things, volatility of oil and gas prices, product supply and demand, competition, government regulation or action, foreign currency valuation changes, foreign government tax and regulation changes, litigation, the costs and results of drilling and operations, Pioneer’s ability to replace reserves, implement its business plans, or complete its development projects as scheduled, access to and cost of capital, uncertainties about estimates of reserves, quality of technical data, environmental and weather risks, acts of war or terrorism. These and other risks are identified from time to time in Pioneer’s SEC reports and public announcements.

     The proposed merger will be submitted to each of Pioneer’s and Evergreen’s stockholders for their consideration, and Pioneer will file with the SEC a registration statement containing the joint proxy statement–prospectus to be used by Pioneer to solicit approval of its stockholders to issue additional stock in the merger and to be used by Evergreen to solicit the approval of its stockholders for the proposed merger. Pioneer will also file other documents concerning the proposed merger. You are urged to read the registration statement and the joint proxy statement–prospectus regarding the proposed merger when they become available and any other relevant documents filed with the SEC, as well as any amendments or supplements to those documents, because they will contain important information. You will be able to obtain a free copy of the joint proxy statement–prospectus including the registration statement, as well as other filings containing information about Pioneer at the SEC’s Internet Site (http://www.sec.gov). Copies of the joint proxy statement–prospectus can also be obtained without charge, by directing a request to: Pioneer Natural Resources Company, Susan Spratlen, 5205 N. O’Connor Blvd., Suite 900, Irving, Texas 75039, or via telephone at 972-969-3583.

     Pioneer and its directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of Pioneer in connection with the proposed merger. Evergreen and its directors and executive officers may be deemed to be participants in the solicitation of proxies from the stockholders of Evergreen in connection with the proposed merger. Additional information regarding the interests of those participants may be obtained by reading the joint proxy statement–prospectus regarding the proposed merger when it becomes available.