Pioneer Natural Resources (PXD) 8-K Regulation FD Disclosure

EXHIBIT 99.1

Lehman Brothers CEO Energy Conference September 5, 2006

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 are subject to a number of risks and uncertainties that may cause Pioneer'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, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, third party approvals, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, availability of drilling equipment, Pioneer's ability to replace reserves, implement its business plans (including its plan to repurchase stock) or complete its development projects as scheduled, access to and cost of capital, uncertainties about estimates of reserves, the assumptions underlying production forecasts, 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. Please see the Appendix to this presentation for other important information.

Delivering on Low-Risk Strategy Over 90% of production and proved reserves in North America Low-risk drilling program Profitable double-digit production growth for 2006-2010 Driven by high-margin / high-return development drilling and resource plays Asset sale proceeds redeployed to partially fund $1.4 billion Capital Budget in 2006 and $1 billion share repurchase program 2007 Capital Budget expected to be more closely aligned with DCF based on June 2006 strip pricing F&D cost expected to average $10 - $15 / BOE for 2007 to 2010 Cash margins projected to improve >25% by 2010 (not price driven) NAV of $54 - $64 / share from proved reserves and low-risk resource potential in existing development areas Additional $10 - $16 / share from resource plays

Targeting Profitable Double-Digit Production Growth Production Targets 2006 - 2010 CAGR Development 10% W/ Risked Resource Plays up to 18% W/ Risked High-Impact Exploration up to 21% Company Target >10% MMBOE Edwards, Uinta-Piceance, Sand Wash & Tunisia Spraberry, Raton, Canada, South Coast Gas, Oooguruk and Clipper High-Impact Exploration 36.5 35.5 Updated 2006 / 2007 Guidance 10+%

Strong Returns on Development Drilling & Projects Internal Rate of Return Before Tax (Reflects June 2006 Strip Prices) Spraberry (West Texas) 35% Raton (Southeast Colorado) 30% Horseshoe Canyon (Alberta, Canada) 60% South Coast Gas (South Africa) 50% Oooguruk (Alaska North Slope) 40% Strong returns also at $55 crude / $6.50 gas

Q1 2006 Q2 2006 Exit Rate US 81 84 86 Canada 6 8 8 Africa 8 7 6 2005 93 89 MBOEPD 95 99 95 - 100 U.S. Canada Africa Note: 1H '05 production of 89 MBOEPD pro forma for discontinued operations; assumes 2005 and 2006 VPP volumes in place for all of 2005 Production Growth On Track Q1 2006 Q2 2006 2006 Exit Rate Q2 '06 production up 4% from Q1 '06 1H '06 production up 9% from 1H '05 On target to meet or exceed high end of forecast 2006 exit rate of 95 - 100 MBOEPD Production from Spraberry, Raton and Canada increasing Ramping up rig count; all necessary rigs under contract at fixed day rates for 2 - 3 years Edwards success adding to future growth Upside potential from resource plays in Rockies, other onshore Gulf Coast areas and Tunisia Oooguruk and South Coast Gas development projects on schedule March Forecast 1H '05 89

Total Budget East 785 615 Total Budget East 480 780 960 0 110 2006 F&D Expected to be $15 - $20 / BOE $1.4 B 2006 Capital Capital for New Reserves ? >70 MMBOE ? $9 - $12 / BOE PUD Drilling Capital ? Reserves Already Booked PUD Drilling: ~55% of $1.4 B Budget Reserve Additions: > 70 MMBOE 1,060 950 110 Development Drilling / Projects (Expect ~100% success rate) New Resource Plays (Expect ~40% - 60% success rate) 2006 # Wells $0.8 B $0.6 B Reserve Adds

Unbooked Resource Potential Drives Down F&D Costs Year End '05 Reserves2 (MMBOE) Resource Potential3 (MMBOE) Spraberry 404 100 Raton 246 70 Canada 24 60 Development Projects4 11 80 Edwards Trend 22 170 Uinta / Piceance / Sand Wash 14 130 Tunisia 4 40 Mid-Continent 136 - Other 4 - Total 865 650 4 Development projects include South Coast Gas, Oooguruk and Clipper 2 Pro forma for discontinued operations 1 Compares favorably to historical 3-year and 5-year F&D costs of $10.62 / BOE and $9.55 / BOE, respectively F&D cost for 650 MMBOE projected at $10 - $15 / BOE1 3 Excludes high-impact exploration

2006 - 2010 Capital Allocation Total Budget Maintance 600 2P Growth 400 100 Risk Success Growth 300 asd 100 2006 - 2010 Average Annual Capital ~ $0.5 B Maintenance Capital Capital to Generate 10% Growth (Mostly Development Drilling) ~ $0.4 B $0.9 B * Level of spending dependent on drilling success Capital to Generate Growth Above 10% (Mostly Resource Plays) *

2006 2007 2010 LOE 28 33 37 2 Cash Margins Improve >25% by 2010 1 Cash margins are pre-tax reflecting revenues less production cost, G&A and interest expense; based on June 2006 strip pricing and costs 2 Based on June strip pricing and growth from development drilling and projects Cash Margins in $ / BOE1 Production mix benefits from lower- cost volume growth (e.g. South Coast Gas, Spraberry, Edwards) G&A cost initiatives Improving unit operating costs related to declining VPP obligations Expiration of legacy oil hedges in 2008 >25% Improvement 2006 - 2010 Cash Flow CAGR 15%2

NAV Significantly Exceeds Current Stock Price NAV 2P 58 Transition 2 Resource Plays 11 Transition 2 Traditional Exploration 3.5 Transition 3 Development NAV range is risked and discounted at 8% - 10% due to long-life nature of the assets Resource Play exposure is substantial, even on a risked basis Risked High-Impact Exploration represents only a small portion of capital, but a large potential future upside $54-$64 Development Resource Plays High-Impact Exploration $10-$16 $4-$9 Significant Unbooked Potential 865 MMBOE - proved ~300 MMBOE - low-risk resource potential ~350 MMBOE - potential resource upside

Spraberry Anchors Growth Glasscock Reagan Upton Midland Martin Spraberry Trend Pioneer Acreage Pioneer's largest asset 315,000 gross acres 4,200 active wells Over 95% operated 2006 Objective: Add Production and Reserves Ramping up Permian drilling program from 190 to 335 wells Rigs increase from 12 at YE 2005 to 17 currently and 20 by YE 2006 Majority of wells in 2006 will test deeper Spraberry Wolfcamp potential Strong Btax IRR: 35% @ June strip Pursue acreage expansion program and bolt-on acquisitions Aggressive leasing campaign: 75K gross acres YTD Recently completed: Up to a 200-well JV with major oil company $35 MM bolt-on acquisition Expect >10% annual production growth through 2010

Edwards Trend Success Continues Increased land position to >235,000 gross acres Strong Btax IRR: 50% @June strip 5 new prospects drilled successfully through Q2 3 discoveries in Q2: Barracuda, Wahoo and Bonita Currently testing; on production late Q3 / Q4 Appraisal / development plans being prepared Stingray discovery Stingray #1 on production Q3 1st of 3 appraisal wells drilling Sinor discovery Development 3-D seismic being permitted Development drilling to begin Q2 '07 Current production of ~5 MMCFPD from 3 wells 3 wells targeting new prospects in Q3 4 rigs working along trend; 6 by year end 2006 drilling program: 35 - 40 wells ~1/3 targeting new prospects 14 wells drilled through July LaSalle Fayette Pawnee 310 BCF Washburn SW Kenedy Mertz / NE Word Stingray Gross Resource Potential: 1-3 TCF Wahoo Bonita Barracuda Existing Gas Fields PXD Fields PXD Focus Area New PXD Discoveries Sinor

Raton Expansion Continues New Mexico Colorado Raton Basin 310,000 gross acres Drilling program increased from 289 wells in 2005 to 330 wells in 2006 2006 program on track 155 wells drilled through July Rig count recently increased from 2 to 3 rigs Strong Btax IRR: 30% @ June strip 2006 Objective: Focus on more efficiently recovering the resource Lower field pressure through wellhead / booster compression and additional pipelines Continue to refine reservoir characterization model to high-grade future drilling locations Continue to actively manage costs via integrated well service model and new frac sand mine Raton Vermejo 2006 production expected to exceed annual growth target of 5% - 7%

Rockies Emerging Resource Plays Lay Creek CBM (Sand Wash Basin) 22 wells from initial 2 pilots on production by year end Currently drilling and testing 3 additional pilots New water treatment facility in place Q3 Columbine Springs CBM (Piceance Basin) 35-well pilot project on production Q3 Water disposal capability in place Castlegate CBM (Uinta Basin) 25-well pilot project on production Q3 Entrada Gas Play (Uinta Basin) 4 wells planned for 2H '06 Shooting additional 3-D seismic Utah Results to be evaluated late 2006 / early 2007 to determine future development plans Piceance Basin Uinta Basin Castlegate Colorado Sand Wash Basin Entrada Utah Columbine Springs Lay Creek

Canada Production Growing Horseshoe Canyon CBM 70,000 gross acres with ~500 locations Drilling program increased from 157 wells in 2005 to 200 wells in 2006 Two rigs on location to complete this year's program after lifting of weather-related road bans Third rig expected in Q3 Strong Btax IRR: 60% @ June strip Mannville CBM ~75,000 gross acres 3 pilots (2 wells each) planned for 2006 4 wells drilled and dewatering Remaining 2 wells being drilled in Q3 Identifying drilling and completion techniques that allow commercial production rates Net resource potential: 250 BCF Calgary Edmonton Horseshoe Canyon Mannville Chinchaga 1H '06 production up 12% from 1H '05

Development Projects On Schedule 7-well subsea tie-back to existing F-A platform Development drilling underway; to be completed by early 2007 Subsea infrastructure and well tie-ins 1H '07 Strong Btax IRR: 50% @ June strip First production 2H '07 Subsequent development phases anticipated post-2012 South Africa - South Coast Gas Gravel drill site constructed 1H '06 Remainder of 2006 Contour and "armor" gravel drill site Procure equipment and services Fabricate modules to be used on drill site Modify drilling rig for 2007 installation Strong Btax IRR: 40% @ June strip First production 2008 Alaska - Oooguruk

Tunisia Provides Core Area Potential Tunisia Algeria Libya * Subject to ETAP participation of up to 50% WI El Hamra Anaguid Jenein Nord Adam BEK Over 5 million net acres Working interests ranging from 20% to 100%* in 5 concessions 9 successful wells drilled to date in Adam Concession (90% success rate) Strong Btax IRRs: >100% @ June strip 2H '06 drilling program Adam: 1 well Jenein Nord: 2 wells; rig contracted for Q4 Borj El Khadra: 1 well Evaluating options for increased gas sales

Positioned to Create Value Low-risk business strategy already delivering 10% annual production growth1 Over 2006 - 2010 period, on track to deliver: Profitable, double-digit production growth from high-return development drilling and resource plays Improved cash margins by >25% Average F&D cost of $10 - $15 / BOE for 2007 - 2010 Increased net asset value per share Continue to reduce share count 26 MM shares repurchased over past two years (17% of shares outstanding) Consider additional repurchases upon completion of current program 1 Pro forma for discontinued operations; assumes 2005 and 2006 VPP volumes in place for all of 2005

Appendix

Pioneer Today Operating Areas Tunisia Nigeria Equatorial Guinea South Africa Sable / South Coast Gas Company Metrics1 Company Metrics1 Total Reserves 865 MMBOE Pre-Tax PV10 $8.6 B % PDP 61% % Gas 55% R / P Ratio 23 Years2 % North America 98% % Operated Production ~90% Pioneer pro forma for discontinued operations as of 12/31/05 Adjusted to include 2006 VPP production and reserves sold Chinchaga Horseshoe Canyon Raton Hugoton Edwards West Panhandle Uinta / Piceance Spraberry Alaska North Slope Mississippi Sand Wash Cook Inlet

June 2006 Strip Prices Crude ($ / BBL) Gas ($ / MCF) 2006 69.61 7.58 2007 75.99 9.18 2008 73.78 8.92 2009 71.81 8.46 2010 70.23 8.05 2011 68.97 7.63 2012+ 68.00 7.31 Note: August 2006 strip prices essentially the same as June strip prices on average over 2006-2012 period.

Senior Notes and Credit Facility Maturities as of 6/30/06 2006 2007 2008 2009 2010 2011 2012 2028 $32 MM 8 1/4% $6 MM 5 7/8% $250 MM 7 1/5% 2016 $527 MM 5 7/8% 2021 $98 MM 4 3/4% Issued $450 MM of 6 7/8% senior notes due 2018 Investment grade covenants Refinanced $346 MM of senior notes maturing in January 2008 Convertible Notes Assumed from Evergreen Subsequent to 6/30/2006, $71 MM of 4 3/4% Convertible Notes due 2021 converted; issued 1.7 MM shares (already included in diluted shares outstanding) and paid $55 MM in cash Expect remaining Convertible Notes ($27 MM) to convert prior to year end If not converted prior to 12/06, Pioneer will redeem for cash at par 2018 $450 MM 6 7/8% $ - 5-Year, $1.5 B Credit Facility $4 MM 6 1/2%

Approximate based on historical differentials to index prices % of production Gas Jul-Dec 2006 2007 2008 2009 Swaps (MMBTUD) 73,932 59,195 15,000 - NYMEX Price ($/MMBTU)1 $ 4.30 $ 7.75 9.10 - Collars (MMBTUD) 90,000 6,164 - - NYMEX Call Price ($/MMBTU)1 $15.15 $12.82 - - NYMEX Put Price ($/MMBTU)1 $6.95 $10.00 - - % Hedged N American Gas2 49% 18% 5% - % Hedged N American Gas (Swaps only)2 22% 16% 5% - Crude Swaps (BPD) 5,000 10,000 10,000 - NYMEX Price ($/BBL) $37.20 $30.96 $30.62 - Collars (BPD) 6,500 2,000 - - NYMEX Call Price ($/BBL) $66.41 $89.50 - - NYMEX Put Price ($/BBL) $41.92 $50.00 - - % Hedge Total Liquids2 28% 30% 20% - % Hedged Total Liquids (Swaps only)2 12% 25% 20% - Total Equivalent % Hedged Total Equiv.2 40% 21% 10% - % Hedged Total Equiv. (Swaps only)2 18% 18% 10% - Hedge Position as of 8/8/2006

Rigs Secured To Execute Plan North American Onshore Growth Areas YE 2005 Q1 '06 Q2 '06 Q3 '06E Q4 '06E Permian 12 12 16 19 20 Raton 3 3 2 3 3 Edwards Trend 2 4 4 4 6 U / P & Lay Creek 1 2 2 3 3 Mississippi 0 1 1 2 3 Canada 2 2 3 3 3 Rigs Operated by Quarter

Capital Cost Creep % Increase % Increase Item 2005 2006YTD Drilling Day Rate 40% 20% Fracs 70% 10% Cement 20% 80% Logging 100% 5% Casing 40% 25% Mud 40% 20% Pumping Units 100% 5% Drill Bits 15% 50% Representative Industry Cost Day Work Rate ($ / Day) WTI Price ($ / barrel) WTI vs. Drilling Capital Correlation (Spraberry Example)

Q1 Q2 Q3 Q1 2000 Q2 2000 Q3 2000 Q4 2000 Q1 01 Q2 2001 Q3 01 Q4 01 Q1 02 Q2 02 Q3 02 Q4 02 Q1 03 Q2 03 Q3 03 Q4 03 Q1 04 Q2 04 Q3 04 Q4 04 Q1 05 Q2 05 Q3 05 Q4 05 Q1 06 Q2 06 LOE 2.99 2.42 2.47 2.18 2.05 2.2 2.33 2.36 2.58 2.89 3.19 3.29 2.88 2.63 2.68 3.02 3.3 3.29 3.44 3.43 3.71 3.81 4.22 4.8 5 5.63 4.81 6.15 6.23 Field Fuel 0.45 0.81 0.96 1.46 1.54 0.9 0.6 0.51 0.49 0.65 0.63 0.7 1 0.72 0.68 0.55 0.65 0.65 0.67 0.67 0.67 0.67 0.67 0.67 0.67 0.67 3rd Party FF 0.12 0.21 0.25 0.35 0.39 Transportation 0.33 0.34 0.33 0.15 0.4 0.48 0.52 0.57 0.54 0.55 0.54 0.55 0.48 0.38 0.37 0.37 0.47 0.47 0.49 0.25 0.88 1.19 1 1.04 1 1.2 Prod Taxes 0.27 0.38 0.37 0.67 0.67 0.79 0.93 1.08 0.76 0.61 0.53 0.5 0.63 0.6 0.43 0.84 0.59 0.55 0.56 0.59 0.59 0.59 0.77 2.23 2.54 2.72 3.32 2.96 3.28 Workover 0.05 0.1 0.16 0.28 0.06 0.11 0.16 0.21 0.16 0.16 0.14 0.3 0.28 0.26 0.17 0.2 0.11 0.15 0.13 0.23 0.28 0.17 0.29 0.62 0.57 0.54 0.56 0.72 0.74 Production Costs (per BOE) Production & Ad Valorem Taxes Q 2 2005 $9.30 Q 3 2005 $2.54 $1.19 $5.00 $0.57 $9.89 Q 4 2005 $9.73 $2.72 $1.00 $5.63 $0.54 $3.32 $ 1.04 $4.81 $0.56 $11.04 $2.96 $1.21 $0.72 Q 1 2006 $6.15 Note: All periods presented have been restated to exclude discontinued operations. Adjusted to Include VPP Production $9.47 $9.06 $9.19 $8.62 $9.89 Workovers LOE Transportation Q 2 2006 $11.45 $3.28 $1.20 $0.74 $6.23 $4.63 $5.38 16% Production Cost LOE Creep

1H 2006 Production Cost vs. Peers PXD 9.68 1.57 NBL 6.53 CHK 7.07 EOG 7.19 RRC 7.37 NFX 8.02 XTO 9.64 KWK 10.83 XEC 11.23 PPP 12 PXP 13.35 $ / BOE 11.25 6.53 7.07 7.19 7.37 8.02 9.64 13.35 12.00 11.23 10.83 1H 2006 Average (9.32) 9.68 if VPP Volumes Added Sources: Banc of America Securities & company financials 1.57

VPP - Adjusted Production Costs Pioneer presents VPP-Adjusted Production Costs (per BOE) and VPP- Adjusted LOE (per BOE) to assist investors in understanding the Company's costs in relation to total volumes produced (reported sales volumes plus VPP delivered volumes). VPP-Production Costs (per BOE) and VPP-Adjusted LOE (per BOE) are calculated as follows: Q2 '05 Q3 '05 Q4 '05 Q1 '06 Q2 '06 Production costs as reported (thousands): LOE $ 42,786 $ 52,856 $ 46,036 $ 52,735 $ 56,071 Total $ 79,640 $ 92,809 $ 93,046 $ 94,683 $ 103,006 Production (MBOE): As reported 8,564 9,387 9,559 8,573 8,999 VPP deliveries 674 714 712 1,421 1,419 VPP-adjusted production 9,238 10,101 10,271 9,994 10,418 Production costs per BOE: As reported: LOE $ 5.00 $ 5.63 $ 4.81 $ 6.15 $ 6.23 Total $ 9.30 $ 9.89 $ 9.73 $ 11.04 $ 11.45 VPP-adjusted: LOE $ 4.63 $ 5.23 $ 4.48 $ 5.28 $ 5.38 Total $ 8.62 $ 9.19 $ 9.06 $ 9.47 $ 9.89 Note: Under GAAP, volumes sold under VPPs are not included in reported production

Certain Reserve Information The U.S. Securities and Exchange Commission (the "SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Pioneer uses certain terms in this presentation, such as "resource", "resource potential" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's guidelines prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer.

Net Asset Value Pioneer does not consider "Net Asset Value" and "Net Asset Value Per Share" to be "non-GAAP financial measures," as defined in SEC rules. Pioneer uses Net Asset Value as an estimate of fair value. Net Asset Value and Net Asset Value Per Share should not be considered as alternatives to Standardized Measure, Stockholders Equity or per share statements of those measures. Pioneer's NAV calculation is based on numerous assumptions that may change as a result of future activities or circumstances. NAV is calculated using strip commodity prices as of January 2006 and is discounted at 10%, unless otherwise indicated. In the context of determining Pioneer's Net Asset Value Per Share, Pioneer adds other tangible assets adjusted for working capital and deducts long-term debt and other liabilities, including future income taxes and the impact of existing hedge positions.