Exhibit 99.1

Independent Petroleum Association of America Oil & Gas Investment Symposium April 8, 2008

Forward-Looking Statements Except for historical information contained herein, the statements, charts and graphs 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 commodity 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, access to and availability of drilling equipment and transportation, processing and refining facilities, 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 and resource potential and the ability to book proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, and 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. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law. Please see the appendix slides included in this presentation for other important information.

Investment Highlights Targeting >20% after-tax cash flow CAGR through 2011 2009 after-tax cash flow expected to double from 2007 Production growth primarily from high-margin, oil-related projects Includes benefit from legacy hedge expirations and reduced VPP obligations Earnings from continuing operations expected to double in 2008 and triple in 2009 compared to 2007 Increasing production per share growth to 14+% CAGR through 2011 Reflects 14+% absolute production growth and assumes no additional share repurchases Core onshore assets driving consistent, repeatable growth (Spraberry drilling acceleration, Raton Basin expanding into Pierre Shale, Edwards and Tunisia) Q1 2008 production expected to be near the upper end of guidance range; up ~20% vs. Q1 20071 Generating free cash flow2 in 2008 and beyond Total proved reserves and resource potential now estimated to be 2.8 billion BOE Additional resource potential from Spraberry downspacing / secondary recovery and Pierre Shale; adds significant production growth and net asset value Drilling inventory increased to ~22,000 low-risk locations Pro forma for Canada divestiture After-tax cash flow from operations less capital expenditures

- 0.1 0.2 0.5 0.6 2006 2007 2008 2009 2010 2011 East 0.756 0.85 1.25 1.8 1.9 2 Targeting >20% After-Tax Cash Flow CAGR After-tax cash flow from operations reflects the divestiture of Canada in late 2007, strip pricing (low end of range reflects December 2007 strip pricing of $88/BBL and $8.50 MCF; high end reflects March 2008 strip pricing of $102/BBL and $9.75/MCF) and expected growth from development drilling and development projects Cash taxes projected to increase in 2010/2011 due to intangible drilling cost credits not offsetting significant earnings growth After-Tax Cash Flow1 ($ billions) 0.8 2011 1.8 - 2.2 Cash flow growth driven by production growth (2/3) and legacy hedge expiration (1/3) 65% of revenue growth from oil-related production growth Generating free cash flow in 2008 and beyond ROCE from continuing operations expected to more than double to 15% - 18% in 2009 compared to 2007 Earnings from continuing operations expected to double in 2008 and triple in 2009 compared to 2007 >20% CAGR 2007 1.1 - 1.4 2008 1.6 - 2.0 2009 1.7 - 2.1 2010 Estimated Cash Taxes2

2008 2009 2010 2011 2012 2013 Historical Production VPP Oil 8 7 7 4 4 0 VPP Gas 5 5 Legacy Hedges 10 Legacy Hedge Expirations Contribute Significant Cash Flow Improvement VPP Oil Obligation 12 Includes 6 MBOPD of unwound hedges for which the losses are locked in and 4 MBOPD hedged at $32 / BBL Cash flow improvements based on March strip pricing ($102/BBL and $9.75/MCF) 23 7 4 Legacy Oil1 Hedges1 Incremental Pre-Tax Cash Flow vs.2008 ($MM)2 - 200 300 400 400 500 MBOEPD 5 10 VPP Gas Obligation 8 5 7 4

2005 2006 2007 2008 2009 2010 2011 Historical Production Production Outlook 30.9 33 36 41 45 52 54.8 1.9 6.3 9 12 Increasing Production Per Share Growth to 14%+ CAGR1 Development Spraberry Raton Edwards Tunisia South Africa Oooguruk Barnett Shale Resource Play Upside Spraberry Edwards Tunisia Pierre Shale Rockies Barnett Shale Cosmopolitan MMBOE 33 31 Production pro forma for Deepwater GOM, Argentina and Canada divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 14+% Per Share CAGR (assumes no additional share repurchases) Per Share CAGR: 16% 36

Core Area Drilling Program Generating Strong Returns in 20081 $85/BBL & $8/MCF (NYMEX) Before Tax $85/BBL & $8/MCF (NYMEX) Before Tax $85/BBL & $8/MCF (NYMEX) Before Tax $95/BBL & $9/MCF (NYMEX) Before Tax $95/BBL & $9/MCF (NYMEX) Before Tax $70/BBL & $7/MCF2 (NYMEX) Before Tax $70/BBL & $7/MCF2 (NYMEX) Before Tax Cash Margin $/BOE IRR DROI3 IRR DROI3 IRR DROI3 Spraberry (West Texas Oil, NGLs & Gas) 55 40% 2.1 50% 2.3 30% 1.7 Raton (Colorado Gas) 30 40% 2.5 50% 2.9 35% 2.1 Edwards Trend (South Texas Gas) 40 40% 1.9 50% 2.2 30% 1.7 Tunisia (Oil & Gas) 75 >100% >3.0 >100% >3.0 >100% >3.0 Cash margins, IRRs and DROIs assume current costs and price differentials. Cash margins are pre-tax reflecting revenues less production costs. Assumes no reduction in costs or price differentials. Discounted Return on Investment (DROI) is defined as present value of future cash flow discounted at 10% divided by discounted capital investment.

Reserves and Updated Resource Potential1 YE '06 Proved Reserves (MMBOE) YE '07 Proved Reserves (MMBOE) Additional Net Resource Potential (MMBOE) Spraberry 440 481 1,0002 Raton CBM/Pierre Shale 250 266 3502 Mid-Continent 113 111 20 Edwards Trend 27 38 100 Tunisia 6 21 110 Barnett Shale 0 16 90 Alaska 0 5 120 Other 38 26 80 Total 8743 964 1,870 Reflects year-end pricing of $95.92/BBL and $6.80/MMBTU (NYMEX) Formerly 145 MMBOE for Spraberry and 125 MMBOE for Raton Pro forma for Canada divestiture 2.8 BBOE of Proved Reserves and Resource Potential

Pioneer is the largest driller and producer in the Spraberry field 869 M gross acres (>50% of Spraberry; >75% HBP) 5,300 active wells 5th largest oil field and 15th largest gas field in the U.S.1 Largest producing field in the Permian Basin (1.7 MM acres) Spraberry production growing; other largest onshore oil fields declining Updated field volumetrics show >30 BBOE OOIP, with an EUR of 3.5 BBOE2 12% - 13% primary recovery on 40-acre well spacing Sustained high commodity prices support enhanced recovery initiatives Additional 6% primary recovery estimated from 20-acre infill drilling Historical waterflood results suggest 9% additional recovery potential Actively progressing initiatives to capture additional resource upside Drilled four successful 20-acre infill wells in Q1; drilling 20 - 25 additional wells in 2008 Planning large-scale secondary recovery project for 2009 Drilling majority of wells to deeper Wolfcamp zone (+20% to reserves and production of typical well) Leveraging advances in completion technology Spraberry - A Growing, Premier Oil Resource Play Source: Energy Information Administration Source: Nehring Associates Data supports PXD resource potential of ~1.0 BBOE

Spraberry - Only Large U.S. Onshore Oil Field Growing 10 Largest Oil Fields in the United States1: Production Growth Since 2003 Spraberry Trend Area Mars-Ursa Thunder Horse Wasson Belridge South Elk Hills Kern River Midway-Sunset Kuparuk River Prudhoe Bay 1997 22.1 31.9 0 15.1 41.1 20.5 48.8 61.6 96.1 252.3 2000 16.9 51.7 0 23.7 41.3 17.3 44.9 56.7 49.6 188.6 2003 19.8 58.1 0 26.1 41.1 18.7 36.7 47.8 58.8 141.3 2006 24.2 61.6 0 24.7 38.9 17.2 30.8 39.6 45.5 92.1 Spraberry Trend Area Mars-Ursa2 Thunder Horse2 Wasson Belridge South Elk Hills Kern River Midway-Sunset Kuparuk River Prudhoe Bay +22% +6% -5% -8% -16% -17% -23% -35% 1) Source: EIA reported booked reserves 2) Offshore Oil Field -5%

Spraberry - Quantifying Additional Resource Potential Net MMBOE Ongoing field development ~200 40-acre spacing and deeper Wolfcamp drilling Excludes YE 2007 proved undeveloped reserves of 248 MMBOE Identified recovery improvements 20-acre spacing on high-graded acreage (~9,500 drilling locations) ~500 Historical downspacing performance indicates 75% - 80% recovery of a 40-acre location [869 M acres / 640 acres per section x 70% high-grade acreage x 12.3 MMBOE OOEIP per section x 6% incremental primary recovery] x 70% NRI Secondary recovery ~300 10 historical waterflood projects have recovered 82 MMBO suggesting 1:2 secondary to primary recovery ratio [(869 M acres / 640 acres per section x 40% floodable acreage x 10.6 MMBO OOIP per section x 9 % incremental secondary recovery) - 82 MMBO previously recovered through waterflood] x 70% NRI ~1,000 Excludes upside from leveraging advances in completion technology: Fracing 5 previously drilled (~12 years ago) horizontal wells with isolation packers

Total net resource of ~1.5 BBOE, including proved reserves and resource potential Multi-year drilling inventory of ~19,000 locations Drilling 350 wells in 2008 Planning a substantial increase in drilling activity beginning in 2009 Justified by strong economics at $95/BBL, significant scale efficiencies from existing operations and zero incremental entry cost Before tax IRR: 50% for 40-acre well and 40% for 20-acre well Expect to add proved reserves of ~250 MMBOE over the next 5 years from resource recovery initiatives Will significantly improve Spraberry organic F&D PDP PUD 1998 161 1999 203 2000 212 2001 236 2002 300 2003 334 2004 351 2005 404 2006 440 2007 481 2008 2009 2013 550 31 Spraberry - Resource Recovery Initiatives Enhance Reserve Growth PXD Spraberry Proved Reserves (MMBOE) 2006 2005 2004 2003 2001 2002 2000 1999 1998 440 404 351 334 236 300 212 203 160 4811 2007 ~50% of YE 2007 total PXD proved reserves 2012 ~250 MMBOE

2005 2006 2007 2008 2009 2010 2011 20 23.581 26.6 28.752 44 2 3.5 Spraberry - Resource Recovery Initiatives Enhance Production Growth >25% of 2007 Total Production Excludes 8 MBOEPD of VPP volumes Production expected to grow ~15% in 2008 based on a 16-rig program Increased drilling combined with resource recovery initiatives provide confidence in a 15% production CAGR through 2011 MBOEPD 24 27 2006 2007 2008 20 21% 2005 15% CAGR 13% ~15% 2011 2008 PXD Acreage (869 M gross) 75 miles 150 miles

New Shale Play in Our Backyard! New shale resource play identified and being developed under existing Raton CBM field Mancos-equivalent, Cretaceous-aged laminated shale 4,000 - 6,000 feet deep Gross overall thickness of 2,200 - 2,800 feet Completions to-date have focused on lower intervals (200 - 400 feet net pay) Play has evolved over past 18 months PXD Pierre Shale position encompasses ~134 M acres (100% HBP) of the 318 M acres leased in Raton 21 TCF OGIP based on whole core evaluations and well control Wells can be drilled from both new and existing pads and tied into extensive CBM infrastructure PXD integrated well service model and drilling efficiencies being employed Total resource potential exceeds 2 TCF 18 BCF proved reserves at YE 2007; expect to reach 70 BCF by YE 2008 and >200 BCF by 2010 ~1,200 risk-adjusted potential drilling locations (80-acre spacing) New Mexico Colorado Raton PXD Pierre Shale PXD Raton CBM Raton: 9th largest U.S. gas field1 1) Source: Energy Information Administration

W Kp1 Kp2 Kp3 Kp4 Kp5 450' 700' 500' 650' 270' Current Production (Kp1) Prospective Producing Zones (Kp2 - Kp5) Avg. Thickness = ~2600 ft Pierre Shale - Well Up The Learning Curve Pierre Shale Technical achievements to-date Identified productive shale intervals in Kp1 - Kp3 Optimized frac design Commerciality demonstrated using vertical drilling Well results 5 vertical wells drilled in the "fairway" producing combined ~2 MMCFPD from one zone Discovery well has been on production for 16 months; second well on production for 10 months Drilled 5 vertical wells currently in the early stages of completion and production to test the boundaries of the play Path forward Horizontal drilling underway to assess upside Identifying productive shale intervals in Kp4 - Kp5 Raton Coals Cross Section of Pierre Shale

Pierre Shale - Strong Economics Confirmed Zero incremental entry cost Target vertical well cost: ~$1.0 MM plus $0.2 MM per interval frac'ed Expected F&D of $10 - $15 / BOE Benefiting from PXD's integrated well service model Tie-in costs minimal due to existing infrastructure Operating costs expected to benefit from scale efficiencies with CBM Expected vertical well IP: 750 MCFPD from one zone Potential upside from additional zones and horizontal drilling Expect similar or better returns than Raton CBM (40% Before Tax IRR @ $8 / MCF) Months Pmean Breakeven 0 750 515 1 599.2607803 411.4924025 2 444.4461843 305.1863799 3 368.7420193 253.2028532 4 321.8928203 221.03307 5 289.282304 198.6405154 6 264.9131288 181.9070151 7 245.814549 168.792657 8 230.3260982 158.1572541 9 217.4377145 149.3072306 10 206.4951555 141.7933401 11 197.0535766 135.3101226 12 188.7985814 129.6416925 13 181.5008414 124.6305777 14 174.9886259 120.1588565 15 169.1304481 116.136241 16 163.8237004 112.4922742 17 158.9869808 109.1710601 18 154.5547726 106.1276105 19 150.4736691 103.3252528 20 146.6996399 100.7337528 21 143.1960159 98.32793094 22 139.9319788 96.08662541 23 136.881413 93.9919036 24 134.0220221 92.02845517 25 131.334639 90.18311877 26 128.8026833 88.44450921 27 126.4117291 86.80272067 28 124.1491579 85.24908843 29 122.0038775 83.77599585 30 119.9660924 82.37671681 31 118.0271158 81.04528617 32 116.1792125 79.77639257 33 114.4154695 78.56528904 34 112.7296868 77.40771825 35 111.1162855 76.29984935 36 109.57023 75.23822462 37 108.0869621 74.21971398 38 106.6623439 73.24147616 39 105.2926096 72.30092529 40 103.9743235 71.39570211 41 102.7043434 70.5236491 42 101.4797895 69.68278882 43 100.298017 68.87130499 44 99.15659133 68.08752605 45 98.0532679 67.32991062 46 96.98597299 66.59703479 47 95.95278755 65.88758079 48 94.95193267 65.2003271 49 93.98175663 64.53413955 50 93.04072352 63.88796348 51 92.12740295 63.26081669 52 91.24046092 62.65178317 53 90.37865166 62.06000747 54 89.54081021 61.48468968 55 88.72584584 60.92508081 56 87.93273608 60.38047878 57 87.16052131 59.85022463 58 86.40829987 59.33369925 59 85.67522367 58.83032025 60 84.96049412 58.33953929 Months MCFPD Pierre Shale Vertical Type Well from Single Zone (0.75 BCF EUR Gross) Based on production performance from first two wells - one on production for 16 months and the other 10 months

2005 2006 2007 2008 0 0 2011 142 155 171 188 268 10 50 Pierre Shale Enhances Raton Growth MMCFPD Drilling ~175 wells in 2008 ~160 CBM wells and ~15 Pierre Shale wells Planning to ramp up drilling in 2009 Combining Raton CBM and Pierre Shale provides confidence in a 10% - 15% production CAGR through 2011 Adding firm pipeline transportation of 100 MMCFPD in 2011 from Raton to Cheyenne to support production growth Provides flexibility to transport gas to both East Coast and West Coast markets Q4 2007 acquisition contributes to significant resource in Pierre Shale ~30% of 2007 Total Production >25% of 2007 Total Proved Reserves 266 MMBOE - 65% PDP / 35% PUD Multi-year Drilling Inventory ~2,400 Locations 350 MMBOE Additional Resource Potential Raton 2006 2007 2008 155 171 10% - 15% CAGR 10% 142 2005 10% >10% 2011

Edwards Trend Success Continues Drilling ~35 wells in 2008 (primarily development wells); similar level expected over the next several years 9 new field discoveries in the Trend to-date brings total discovered gross resource potential to 450 - 650 BCF One Q3 2007 discovery believed to be largest new field in Edwards Trend in last 30 years with gross resource potential of ~200 BCF >80% success rate on new field discoveries Last 6 wells tested 10 - 18 MMCFPD1 each Production currently >70 MMCFPD 60% of >900 sq mi 3-D seismic shoot completed; remainder to be completed by year-end 2008 ~310 M gross acres 2005 2006 2007 2008 40 39 53.7 64.4 3 MMCFEPD 2006 2007 2008 39 54 40 >25% 38% 2005 Not indicative of expected stabilized production rate ~10% of 2007 Total Production 38 MMBOE Proved Reserves Strong Returns: 40% IRR / 1.9 DROI @ $8 / MCF Multi-year Drilling Inventory ~200 Locations 100 MMBOE Additional Resource Potential

Barnett Shale - PXD Has Commenced Drilling Expansion / Tier 2 Area Drilling ~20 wells in 2008 Participating in 6 wells with Devon (50% WI) in Wise County First PXD-operated rig has commenced drilling in Parker County Expect to ramp up drilling program during 2009 Targeting production growth from ~15 MMCFEPD today to 100 MMCFEPD by 2011 Tier 1 Core Ft. Worth PXD built ~80 M gross acreage position in 2007 16 MMBOE Proved Reserves Multi-year Drilling Inventory >450 2P Locations 90 MMBOE Additional Resource Potential

Tunisia Holds Large Drilling Inventory & Growth Potential Drilling 15 - 17 wells in 2008 1 discovery in Jenein Nord and 2 successful appraisal wells in Adam in Q1 Additional 3-D seismic completed in Jenein Nord and 3-D program ~50% completed in Anaguid Jenein Nord production facilities on schedule Production commenced late Q4 '07 Will gradually increase production during 2008 as wells tied in and gross facility capacity expanded from 5 MBOPD currently to 10 MBOPD by the end of Q2 and 20 MBOPD by year-end 2008 Additional net production of 3 - 4 MBOEPD from non-operated Adam block Pursuing project for increased gas sales 1) Assumes ETAP backs in for 50% of PXD working interest 2005 2006 2007 2008 2.585 2.585 4.264 8.1 1 MBOEPD 2006 2007 2008 3 4.5 80% - 90% 65% 3 2005 Highest Returns in Company >100% IRR / >3.0 DROI @ $85 / bbl 21 MMBOE Proved Reserves 110 MMBOE Additional Resource Potential ~3 MM gross acres in Tunisia

Alaska Provides Large Oil Resource Potential Oooguruk Resource potential: 70 - 90 MMBO Only 5 MMBO proved reserves booked as of YE 2007 Expansion opportunities First independent operated project on the North Slope Production and handling agreement in place Development drilling underway Expect to drill 11 - 13 wells in 2008 First production expected Q2 with first sales after scheduled mid-year maintenance at KRU production facilities Net sales expected to reach 3 - 4 MBOPD by year-end 2008 Cosmopolitan Resource potential: 30 - 50 MMBO Horizontal drilling from onshore pad Initial unstimulated extended well test results encouraging 600 BOPD from Hemlock zone; 400-500 BOPD from Starichkof zone Permitting and facilities planning during 2008; next well expected to be drilled in 2009 with first production 2011 Cosmopolitan Discovery PXD 100% WI (Operator) Oooguruk Project PXD 70% WI (Operator) Total resource potential of 120 MMBO Peak net production of >20 MBOPD in 2012 - 2013

Investment Highlights Targeting >20% after-tax cash flow CAGR through 2011 2009 after-tax cash flow expected to double from 2007 Earnings from continuing operations expected to double in 2008 and triple in 2009 compared to 2007 Generating free cash flow in 2008 and beyond Increasing production per share growth to 14+% CAGR through 2011 Low-risk drilling inventory supports consistent, repeatable growth Total proved reserves and resource potential now estimated to be 2.8 billion BOE including new resource estimates for Spraberry and Pierre Shale

Appendix

1) Approximate based on historical differentials to index prices 2) % of production 3) Represents blended Mont Belvieu posted price Gas 2008 2009 2010 Swaps - (MMBTUPD) 200,990 19,795 5,000 NYMEX Price ($/MMBTU)1 $ 8.44 $ 9.45 $ 8.54 % Hedged U.S. Gas2 ~55% ~5% - Crude Swaps - Old (BPD) 4,000 - - NYMEX Price ($/BBL) $ 32.00 - - Swaps - New (BPD) 11,062 8,000 4,000 NYMEX Price ($/BBL) $ 76.15 $ 79.43 $ 85.21 Collars - New (BPD) 3,000 2,000 - NYMEX Call Price ($/BBL) $ 80.80 $ 76.50 - NYMEX Put Price ($/BBL) $ 65.00 $ 65.00 - Natural Gas Liquids Swaps - (BPD) 876 1,000 1,000 Blended Index Price ($/BBL)3 $ 49.82 $ 47.41 $ 46.15 % Hedged Total Liquids2 ~40% ~20% ~10% Hedge Position as of 3/31/2008 HEDGING STRATEGY Capture Spikes Protect Capital Budget and Project Economics

2008 After-Tax Cash Flow Sensitivity ($MM) 850- 970 970 - 1,090 1,090 - 1,200 1,200 - 1,320 1,320 - 1,430 1,430 - 1,550 N Y M E X G A S NYMEX OIL Estimated after-tax cash flow at April strip pricing 24

2009 After-Tax Cash Flow Sensitivity ($MM) 1,090- 1,310 1,310 - 1,540 1,540 - 1,770 1,770 - 1,990 1,990 - 2,220 2,220 - 2,450 N Y M E X G A S NYMEX OIL Projected after-tax cash flow using 2009 strip pricing as of April 2008 25

Historical Spraberry Waterfloods Estimated incremental waterflood recovery of 9% of OOIP Documented benefit from water injection Rapid production response Upside resource potential on Pioneer acreage ~300 MMBO Planning large-scale project for 2009

Spraberry 40-Acre Type Well Payout = 3 years (23.8 MBOE) 5 10 15 20 25 Spraberry 40-Acre Type Well Pricing: $85/BBL & $8.00/MCF BTax IRR: 40% BTax DROI: 2.1 Gross EUR: 100 MBOE Gross Cost: $1.1 MM 60% reserves = 11.6 years

Pierre Shale - Reservoir Characteristics Reservoir Properties Barnett Pierre (Kp1 only) Depth (ft) 4,000 - 9,000 4,000 - 6,000 Thickness (ft) 150 - 800 200 - 800 Porosity (%) 3 - 6 2 - 6 Maturity (Ro) 1.0 - 2.0 2.0 - 2.8 Clay Content (%) 15 - 30 15 - 35 TOC (%) 3.0 - 8.0 1.6 - 2.6 Pierre Shale Raton Coals Quick-look Metrics Pierre Net acreage 134,000 Risked prospective acreage 88,000 OGIP/section (BCF) 100 Recoverable gas/section (BCF) 16 Risked prospective sections 138 Net risked recoverable gas (TCF) >2

Raton CBM Well Type Curve Years 2004 - 2006 Avg 0 100 1 150 2 157 3 153 4 140.5601195 5 130.0131103 6 120.257502 7 111.2339114 8 102.8874111 9 95.16719519 10 88.02627013 11 81.42116847 12 75.3116844 13 69.66062897 14 64.43360373 15 59.59879133 16 55.12676184 17 50.99029365 18 47.16420773 19 43.62521436 20 40.35177138 21 37.32395307 22 34.52332885 23 31.93285107 24 29.53675128 25 27.32044421 26 25.27043901 27 23.37425713 28 21.62035634 29 19.9980605 30 18.49749457 Years MCFPD Raton CBM well type curve reflects a combination of initial wells in a section and infill drilling Initial wells require dewatering; infill wells do not Avg. Working Interest: ~96% Avg. Net Revenue Interest: ~84% Mean EUR (Gross): 0.8 BCFE1 Drilling Cost: $0.45 MM / Well BTax IRR: 40% @ $8 / MCF (DROI: 2.5) Expected Avg. Well Life: 35 Years 1) Reflects average EUR for 2004 - 2007 drilling program, which included a mix of initial wells in a section and infill drilling. Similar mix and EURs expected from 2008 program. Dewatering Period

1st Qtr 0 3000 1 2250 2 1687.5 3 1265.6 4 949.2 5 711.9 6 533.9 7 400.5 8 300.3 9 225.3 10 168.9 11 126.7 12 95 13 71.3 14 53.5 15 25 Tunisia Type Curve Silurian type curve based upon average well performance to-date Working Interest1: 20% - 50% Net Revenue Interest1: 17% - 44% Avg. EUR (Gross): 4.3 MMBO / well Additional upside from gas and condensate sales Drilling & Completion Cost: $9 - $10 MM / well BTax IRR: >100% @ $85 / BBL (DROI: >3.0) Expected Avg. Well Life: 15 years BOPD Years 1) Assumes ETAP backs in for 50% of PXD working interest

South Africa Now Producing Oil & Gas Net production currently ~3.5 MBOEPD Includes Sable oil and gas & condensate from initial South Coast Gas wells Production from project's largest South Coast Gas well now planned for late 2008 / early 2009 Sable oil field life extended as a result of higher oil prices 90 MMCFPD Sable gas injection well (~90% of SCG reserves) was intended to commence production upon Sable oil field abandonment Anticipate producing Sable oil and gas simultaneously after facilities modifications completed in late 2008 / early 2009 Strong cash margins reflecting Brent-related pricing Mossel Bay Synfuels Plant F-A Pipeline to Shore Sable Oil Field F-A Platform ATLANTIC OCEAN Cape Town 380km Initial development Sable gas production (2008 / 2009) Block 9

Delivering Consistent Production Growth 2005 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 2008 East 85 90 89 96 101 103 109 90 103 892 1) Production pro forma for Deepwater GOM, Argentina and Canada divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 Q1 '07 production impacted by weather-related losses in Raton, Mid-Continent and Spraberry totaling ~3 MBOEPD YE shares outstanding of 119 MM 2006 Q2 '07 MBOEPD1 Q1 '07 Q3 '07 96 101 Q4 '07 Delivered 14% production per share growth in 2007 Average Shares Outstanding (MM) 141 128 1223 85 2005

Production (MBOEPD)1 Q4 '06 Q1 '07 Q2 '07 Q3 '07 Q4 '07 Spraberry 25 25 26 27 28 Raton 27 25 28 29 31 Edwards 6 7 8 10 10 Mid-Continent 21 20 20 22 20 Other U.S. 6 6 6 6 6 Total N. America 85 832 88 94 95 Tunisia 3 4 5 5 3 S. Africa 4 2 3 2 5 Total 92 892 96 101 103 1) Restated to exclude Canada discontinued operations 2) Primarily reflects impact of weather-related production losses

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 Q3 06 Q4 06 Q1 2007 Q2 2007 Q3 2007 Q4 2007 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 5.61 6.19 6.28 6.94 7.18 7.17 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 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 0.79 0.8 0.93 0.98 1 0.96 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 3.5 2.5 3.24 3.31 3.23 2.99 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 0.81 0.45 0.69 0.85 0.83 0.7 Production Costs (per BOE)1 Production & Ad Valorem Taxes Q 4 2006 Q 1 2007 VPP-Adjusted $8.54 $9.55 Workovers LOE Third Party Transportation Q 2 2007 $5.38 Production Cost LOE $5.31 $9.94 $2.50 $0.80 $0.45 $6.19 $10.47 $6.01 Q 4 2007 $12.08 $3.31 $0.98 $0.85 $6.94 $10.69 $6.27 Q 3 2007 $11.14 $3.24 $0.93 $0.69 $6.28 $10.35 $6.28 $12.24 $3.23 $1.00 $0.83 $7.18 1) Restated to exclude Canada discontinued operations $11.82 $2.99 $0.96 $0.70 $7.17

VPP - Adjusted Production Costs Pioneer presents VPP-Adjusted Production Costs (per BOE) and VPP- Adjusted LOE (per BOE) to assist investors in considering the Company's costs in relation to the total BOEs (reported sales volumes plus VPP delivered volumes) in connection with which those costs were incurred. VPP-Production Costs (per BOE) and VPP-Adjusted LOE (per BOE) are calculated as follows: Q4 '06 Q1 '07 Q2 '07 Q3 '07 Q4 '07 Production costs as reported (thousands): LOE $ 52,470 $ 50,395 $ 60,555 $ 66,614 $ 68,161 Total $ 84,325 $ 89,448 $105,378 $113,554 $112,358 Production (MBOE): As reported 8,481 8,028 8,725 9,273 9,506 VPP deliveries 1,395 1,334 1,344 1,352 1,345 VPP-adjusted production 9,876 9,362 10,069 10,625 10,851 Production costs per BOE: As reported: LOE $ 6.19 $ 6.28 $ 6.94 $ 7.18 $ 7.17 Total $ 9.94 $ 11.14 $ 12.08 $ 12.24 $ 11.82 VPP-adjusted: LOE $ 5.31 $ 5.38 $ 6.01 $ 6.27 $ 6.28 Total $ 8.54 $ 9.55 $ 10.47 $ 10.69 $ 10.35

Op Cost G&A Interest DD&A PXD 11.85 3.62 3.63 9.98 PXD VPP-Adjusted 10.26 3.14 3.14 8.64 PEER AVG 10.18 2.65 2.25 12.32 CS Universe 11.04 3.72 2.98 13.61 9 Months 2007 All-in Costs vs. Peers Source: Credit Suisse 9 Months 2007 All-in Costs ($ / BOE)1 Includes production costs (including production taxes), G&A (excluding capitalized G&A for full-cost companies), DD&A and interest expense Pro forma for Canada divestiture CS Universe consists of 37 E&P companies $29.08 Production $31.35 3 G&A DD&A Interest $25.18 2 2

(MMBBLS) Q1 Q2 Q3 Q4 Total 2005 - - - - - 2006 0.8 0.8 0.8 0.8 3.2 2007 0.8 0.8 0.7 0.7 3.0 2008 0.7 0.7 0.7 0.8 2.9 2009 0.7 0.7 0.7 0.6 2.7 2010 0.6 0.6 0.6 0.7 2.5 2011 0.3 0.3 0.4 0.4 1.4 2012 0.3 0.3 0.3 0.3 1.2 (BCF) Q1 Q2 Q3 Q4 Total 2005 2.4 4.0 4.3 4.3 15.0 2006 3.7 3.7 3.6 3.5 14.5 2007 3.5 3.5 3.5 3.5 14.0 2008 2.7 2.7 2.8 2.8 11.0 2009 2.5 2.5 2.5 2.5 10.0 Impact of Volumetric Production Payments (VPP) Schedule of Oil VPP Volumes Schedule of Gas VPP Volumes

($ Million) Q1 Q2 Q3 Q4 Total Gas / Oil Gas / Oil Gas / Oil Gas / Oil Gas / Oil 2005 11 / - 19 / - 21 / - 20 / - 71 / - 2006 16 / 27 20 / 28 19 / 28 18 / 29 73 / 112 2007 16 / 26 18 / 27 19 / 27 18 / 27 71 / 107 2008 11 / 25 14 / 25 14 / 26 13 / 26 52 / 102 2009 11 / 24 12 / 24 13 / 24 12 / 24 48 / 96 2010 - / 22 - / 22 - / 22 - / 22 - / 88 2011 - / 10 - / 10 - / 10 - / 11 - / 41 2012 - / 9 - / 10 - / 10 - / 10 - / 39 Total Proceeds & Other Comprehensive Income $900 Impact of Volumetric Production Payments (VPP) Amortization of VPP Deferred Revenue & Other Comprehensive Income1 1) Deferred revenue and other comprehensive income will be amortized over the term of the VPP as an increase to Oil and Gas Revenues. Pioneer retains responsibility for 100% of operating expenses.

Future Amortization of Deferred Losses on Terminated Commodity Hedges1 1) Deferred losses will decrease oil and gas revenues for the periods shown. Excludes deferred hedge gains and losses associated with derivatives terminated in conjunction with the VPPs Oil Gas Total (Cash / Noncash) Total (Cash / Noncash) 1st Qtr 2008 24 (18 / 6) - (- / -) 2nd Qtr 2008 30 (24 / 6) - (- / -) 3rd Qtr 2008 30 (24 / 6) - (- / -) 4th Qtr 2008 29 (23 / 6) - (- / -) 1st Qtr 2009 5 (5 / -) - (- / -) 2nd Qtr 2009 5 (5 / -) - (- / -) 3rd Qtr 2009 5 (5 / -) - (- / -) 4th Qtr 2009 5 (5 / -) - (- / -) 1st Qtr 2010 4 (4 / -) - (- / -) 2nd Qtr 2010 5 (5 / -) - (- / -) 3rd Qtr 2010 5 (5 / -) - (- / -) 4th Qtr 2010 4 (4 / -) - (- / -) ($ Millions)

Senior Notes and Credit Facility as of 12/31/07 2007 2008 2009 2010 2011 2012 2028 $6 MM 5.875% $250 MM 7.20% 2016 $527 MM 5.875% 2018 $450 MM 6.875% $1,113 MM2 $1.5 B Credit Facility $4 MM 6.50% Maturities and Balances1 2017 $500 MM 6.65% Net debt: $2.8 B Net debt to book capitalization: 47% Excludes net discounts and hedge losses of ~$94 MM Subsequent to year-end, refinanced $500 MM of credit facility with 2.875% convertible senior notes due 2038, with a first put/call in 2013

Finding & Development Costs "Finding and development costs per BOE" means total costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

Certain Reserve Information Cautionary Note to U.S. Investors -- 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 potential," "total resource," "OOIP," "OGIP," "OOEIP," "EUR" or other descriptions of volumes of reserves that the SEC's guidelines strictly 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. U.S. investors are urged to consider closely the disclosure in our most recent Form 10-K, file No. 1-13245, available from us at Investor Relations, 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039. You can also obtain this form from SEC by calling 1-800- SEC-0330.