EXHIBIT 99.1(a)

Howard Weil Energy Conference April 3-4, 2007

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 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. Pioneer undertakes no duty to publicly update these statements except as required by law. Please see the Appendix to this presentation for other important information.

2007 Focus - Low-risk, Double-digit Growth Continue to grow production with a target of 10+% Emphasis on North America which grew 12% in 2006 Continue to execute on low-risk development drilling at Spraberry and Raton Proven resource plays and growth assets with large drilling inventory Grew a combined 15% in 2006 with similar performance expected in 2007 Establish first production at South Coast Gas (2H '07) and Oooguruk (2008) Convert Tunisia and Edwards Trend expansion areas into growth vehicles Follow up on 11 new discoveries over past year Continue to expand core areas with attractive bolt-on acquisitions Added ~575 M gross acres with 150 MMBOE resource potential in 2006 Advance several unconventional resource plays initiated in 2006 Implement new $300 MM share repurchase program Repurchased ~9 MM shares at ~$39 in 2006 Evaluate the formation of an upstream Master Limited Partnership Confidence to Deliver in 2007 and Beyond

2007 - 2010: Targeting Double-Digit Production Per Share Growth 2005 2006 2007 2008 2009 2010 Historical Production Production Outlook 33.4 35.9 39.4 43 48.9 56.57 1.8 7.7 15.3 21.5 Development Spraberry Raton Canada Edwards Tunisia South Coast Gas Oooguruk Clipper Resource Plays Edwards Tunisia Rockies Production Per Share Growth Forecast 2007 - 2010 CAGR Development 10% - 12% With Risked Resource Plays up to 20% MMBOE 36 Actual: 7% Per Share: 19% 10+% 33* * 2005 production pro forma for divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 (i.e. volumes effective 2/1/05 plus 9 MBOEPD effective 1/1/06)

Strong Returns on 2007 Development Drilling & Projects1 Current Cost Environment $60/BBL & $7.50/MCF Before Tax $60/BBL & $7.50/MCF Before Tax $60/BBL & $7.50/MCF Before Tax Sensitivity:2 $50/BBL & $5.50/MCF Before Tax Sensitivity:2 $50/BBL & $5.50/MCF Before Tax All-in F&D Cost $/BOE Cash Margin $/BOE IRR DROI3 IRR DROI3 Spraberry (West Texas Oil & Gas) 11 45 35% 1.8 25% 1.5 Raton (Colorado Gas) 5 27 40% 2.5 25% 1.7 Edwards Trend (Gas) 10 37 45% 2.2 25% 1.6 Tunisia (Oil & Gas) 2 55 >100% >3.0 >100% >3.0 South Africa Gas (Gas Indexed To Oil) 13 36 40% 1.8 30% 1.4 Oooguruk (Alaska Oil) 8 44 40% 1.8 30% 1.5 1) Cash margins, IRRs, DROIs and F&D costs assume current costs / differentials. Cash margins are pre-tax reflecting revenues less production costs. 3) Discounted Return on Investment (DROI) is defined as present value of future cash flow discounted at 10% divided by discounted capital investment. 2) Sensitivity case assumes no reduction in costs or differentials.

FY '05 FY '06 FY '07 20 24 27 2 Spraberry Resource Play - Cornerstone of Growth 20 1) 2005 production assumes 2005 and 2006 VPP volumes in place for all of 2005 (i.e. volumes effective 5/1/05 plus 9 MBOEPD effective 1/1/06) 24 MBOEPD 15% - 20% 20051 2006 2007 21% Oil and gas production grew 21% in 2006 vs. 2005 Wolfcamp completions adding incremental reserves and production of >20% to typical Spraberry wells Aggressive drilling program continues 14 - 16 rigs expected to drill 300 - 350 wells, with majority drilled to deeper Wolfcamp zone Planning to drill 450 wells in 2008 Integrated operations significantly reducing LOE Legacy ownership interest in 3 gas plants Acquired 14 pulling units in late 2006 Continuing to pursue acreage expansion and bolt-on acquisitions Added ~230 M gross acres during '06 from bolt-on acquisitions with ~100 MMBOE resource potential Production expected to grow 15% - 20% in 2007 825 M gross acres 4,800 active wells (>95% operated) Largest operator ~25% of Total PXD Production ~50% of Total Proved Reserves Multi-year Inventory (~4,000 Locations)

Added ~150 MMBOE resource potential Included proved reserves of 133 MMBOE (primarily PUDs) and production of ~2,000 BOEPD Resulted from: Leasing ~250 M gross acres including University Lands Purchasing ~145 M gross acres in bolt-on acquisitions Entering joint ventures with 2 majors (drill to earn beginning 2006) Major oil company purchase metrics Purchase price: $145 MM Increased production from ~2,000 BOEPD in August 2005 to ~6,000 BOEPD at year-end 2006 Current net present value of resource potential is ~$600 MM Continued to Acquire Quality Spraberry Acreage in 2005 / 2006 Proven Field Extensions Wells drilled by Pioneer and others have delivered IPs at or above typical Spraberry well Midland Spraberry Field Legacy Acreage 2005-2006 Leasing 10 Miles University Lands University Lands 6

PDP PUD Total 2001 164 72 236 27.16667 27.1667 2002 177 123 300 29.333 29.332 2003 180 154 334 29 29 2004 194 157 351 29.166 29.166 2005 199 205 404 29.39667 28.6667 2006 212 228 440 33.343 23.581 Spraberry F&D is Best Measured on an "All-in" Basis Proved Reserves (MMBOE) 236 300 334 351 404 440 PDP PUD 2001 2002 2004 2005 2006 2003 1) Excludes discontinued operations 2) Production includes VPP volumes of 733 and 9,853 BOEPD for 2005 and 2006, respectively Spraberry has delivered ~50% of PXD's reserve adds1 in recent years (mostly PUDs) Drilled >4,000 wells since early 1980s Recorded >95% reserves as acquisitions or revisions rather than extensions / discoveries which led to near infinite organic F&D Acquisition timing generally results in reserve recognition and drilling in different years Therefore, Spraberry F&D should be viewed over a multi-year period on an "all-in" basis All-in F&D ($/BOE) 2001 - 2006: ~$3 Current: ~$11 27 29 29 29 29 33 100 85 119 117 188 300 Production2 (MBOEPD) Well Count

Raton Expansion Continues New Mexico Colorado Raton 310 M gross acres Receives Mid- Continent Prices Raton FY '05 FY '06 FY '07 142 155 165 6 MMCFEPD 7% - 10% 2005 2006 2007 CBM production grew 10% in 2006 vs. 2005 300 wells drilled Drilling program, pipeline expansion and compression contributed to strong production growth 2 - 3 rigs expected to drill 250 - 300 wells in 2007 Integrated well services continue to drive cost efficiencies Adding wellhead compression throughout field Production expected to grow 7% - 10% in 2007; low end of range reflects early Q1 weather impacts, now back on track 142 155 10% CIG Pipeline ~25% of Total PXD Production ~25% of Total Proved Reserves 3 - 4 Year Inventory (~1,100 Locations)

Edwards Trend Expansion on Schedule 2006 drilling program focused on exploration and appraisal activities, not development drilling Drilled 6 discoveries with gross resource potential of 150 - 325 BCF 2007 drilling program (35 wells, including 2 - 3 new prospects) focusing primarily on development drilling 6 rigs available of which 2 are used to drill horizontal sections Shooting 850 mi2 of 3-D on discoveries to more accurately locate horizontal wells While 3-D being completed, focusing on: Lower-risk development drilling at Pawnee and on new discoveries where 3-D exists 5 recent development wells tested at average initial rate of >4 MMCFPD Refracs of existing horizontal wells at Pawnee to increase production and reserves Initial results indicate increased rates by 4x -10x with a one year or less payout Current net production: >45 MMCFPD Production on track to meet or exceed projected 20% - 25% growth rate for 2007 270 M gross acres FY '05 FY '06 FY '07 39.8 39.4 48 2 MMCFEPD 20% - 25% 2005 2006 2007 40 39

New Discovery in Canada 2006 discovery on proven gas trend Shallow Devonian carbonate reservoir Excellent reservoir quality High rate, high return project First production in April 2007 Initial rate of 18 MMCFPD from 3 wells, increasing to 24 MMCFPD (plant capacity) Additional growth opportunities 375,000 acres leased (<$70 per acre) New discovery contributes to expected 2007 production growth in Canada of 30% - 35% FY '05 FY '06 FY '07 41 48 63 2 MMCFEPD 30% - 35% 2005 2006 2007 41 48 Horseshoe Canyon Chinchaga New Discovery

New Discovery in Canada Provides Upside PhotoshopElements.Image.4 PXD's 375K Acres Existing Fields (shown in pink) 3rd Party Plant & Sales Point Regional Sales Pipeline Extension of Devonian & Cretaceous age gas field trend Over 2 TCF produced to date P50 - P10 field size range: 8 - 75 BCF Pioneer's initial production rates 5x - 10x historical levels Variable permeability; unusually high in producing wells Drilled short laterals (~300') Producing from only first of seven look-alike prospects Additional drilling next winter (winter-only access area) Future wells benefit from 2006 facility investment Two have tested gas, awaiting development 50 - 180 BCF resource potential PXD 40 Mile Pipeline 11

Expandable Production Facilities 24 MMCFPD of compression capacity - Expandable to 40 MMCFPD 8" pipeline built 40 miles to gas plant Future drilling success easily tied in Space for Additional Compressors +16 MMCFPD 3 Compressors x 8 MMCFPD 12

Tunisia Fast Becoming New Core Area Acquired ~1,200 km2 of 3-D seismic in 2006 to optimize drilling program for Adam, Jenein Nord and Borj El Khadra 30+ identified prospects with resource potential as large as 25 MMBOE 5 recent discoveries 3 on PXD-operated Jenein Nord block (first 2 tested at >12 MBOEPD) 1 on Adam 1 on Borj El Khadra Net oil and gas production currently >4 MBOEPD Includes Adam discovery and 1 successful Q1 Adam appraisal well Production from recent Jenein Nord discoveries and second Adam appraisal well expected to come on throughout 2007 Adam in Q2 and Jenein Nord in Q4 Expect to drill at least 9 additional wells through YE 2007 Includes appraisal of recent BEK discovery Pursuing options for increased gas sales Production expected to grow over 30+% in 2007 Tunisia Algeria Libya FY '05 FY '06 FY '07 3 3 3.9 0.6 MBOEPD 30+% 2005 2006 2007 3 3 ~4 MM gross acres in 5 concessions (20% - 50% interest) >90% Drilling Success Since 2003

2007 Tunisia Drilling and Facilities Program Adam Borj El Khadra Jenein Nord Jenein Nord (PXD-Operated), Adam, Borj El Khadra El Hamra (PXD-Operated), Anaguid PXD Concessions (5) Nakhil (Borj El Khadra) Encountered oil zone and tested at >1,000 BOPD Planning appraisal program Karma (Adam) Producing ~4 MBOPD gross Hawa & Nour 2 (Adam) 2 successful appraisal wells 1 currently producing and 1 to be on line during Q2 Jenein Nord Production Facilities Plans to construct oil production facilities well underway First production Q4 Waha & Cherouq (Jenein Nord) Initial discoveries Tested a combined >12 MBOEPD (70% oil and 30% gas and condensate) El Badr (Jenein Nord) Encountered ~35 meters of oil bearing sands Testing mid-April OMV Jenein Sud Discoveries 2 recently announced gas and condensate discoveries Discoveries (5) Appraisals (2) Additional 2007 Wells (9) OMV Discoveries (2)

South Coast Gas Project On Schedule Subsea tie-back to existing F-A platform Drilling commenced on final development well Subsea infrastructure and well tie-ins 1H '07 First production expected 2H '07 Gas production ramps up as existing supplies for GTL plant decline Strong margins; minimal production costs Gross reserve potential: >200 BCFE Expansion opportunities post 2012 South Africa production expected to grow 20% - 25% Subsea installation commences at South Coast Gas FY '05 FY '06 FY '07 6.6 4.1 2.5 2.7 0.3 South Africa MBOEPD 20% - 25% 2005 2006 2007 South Coast Gas 7 4 Sable Oil

2007 Alaska Activities 2007 Alaska Activities Beaufort Sea Cosmopolitan Discovery PXD 50% WI (Operator) Test previous discovery in 2H Oooguruk Project PXD 70% WI (Operator) Construction continuing; drilling 2H NPRA Exploration PXD 20% WI 2-well drilling program in 1H (National Petroleum Reserve Alaska)

Oooguruk Project On Schedule Installing production modules and export pipeline Rig to be installed in April, drilling to commence late 2007 First oil production expected 2008 Peak gross production of 15 - 20 MBOPD in 2010 Gross reserve potential of 70 - 90 MMBO All-in F&D ~$8 / BOE No reserves booked to date Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities Expansion opportunities BEAUFORT SEA Oooguruk Prudhoe Bay Kuparuk River Alpine TAPS 17

Emphasis on Value Creation Low-risk strategy Long-term growth visibility Large drilling inventory Attractive returns Operating strength Financial flexibility Confidence to Deliver in 2007 and Beyond

Appendix

FY '05 FY '06 '06 Exit Rate US 74 83 2 85 Canada 7 8 2 9 Africa 10 7 2 7 Production Growth on Track MBOEPD 91 2005 production pro forma for divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 (i.e. volumes effective 2/1/05 plus 9 MBOEPD effective 1/1/06) 98 U.S. Canada Africa 101 March '06 Forecast Exit Rate (95 - 100) North America 2006 production up 12% from 20051 Driven by Spraberry (+21%), Raton (+10%) and Canada (+18%) Total PXD 2006 production up 7% from 20051 Strong growth in North America partially offset by expected decline in Sable oil field in South Africa Total PXD Q4 production of 101 MBOEPD exceeded March '06 forecast exit rate Produced ~36 MMBOE in 2006 (high end of 33 - 37 MMBOE March '06 guidance) 2005 2006 Q4 '06

Spraberry Type Curve (w/o Wolfcamp) Years Oil Wet Gas Dry Gas MCF Dry Gas (BOE) 0 38 97.33 49.73 7 8 1 22.87 43.04 21.99 3.67 6.03 2 18.18 34.53 17.64 2.94 4.83 3 15.78 33.51 17.12 2.85 4.69 4 13.77 28.9 14.76 2.46 4.05 5 12.34 24.39 12.46 2.08 3.41 6 11.22 24.64 12.59 2.1 3.45 7 10.31 24.2 12.36 2.06 3.39 8 10.25 22.21 11.35 1.89 3.11 9 9.48 22.47 11.48 1.91 3.15 10 8.83 20.73 10.59 1.76 2.9 11 8.14 21.73 11.1 1.85 3.04 12 7.73 23.19 11.85 1.97 3.25 13 7.41 18.96 9.69 1.61 2.65 14 7.19 17.89 9.14 1.52 2.5 15 7.03 17.59 8.99 1.5 2.46 16 6.87 18.23 9.31 1.55 2.55 17 6.61 17.79 9.09 1.52 2.49 18 6.33 16.97 8.67 1.44 2.38 19 6.08 16.29 8.32 1.39 2.28 20 5.84 15.64 7.99 1.33 2.19 21 5.6 15.01 7.67 1.28 2.1 22 5.38 14.41 7.36 1.23 2.02 23 5.16 13.83 7.06 1.18 1.94 24 4.96 13.27 6.78 1.13 1.86 25 4.76 12.74 6.51 1.08 1.78 Years BOEPD Oil NGL Gas Avg. Working Interest: ~90% Avg. Net Revenue Interest: ~75% Mean EUR (Gross): 110 MBOE With Wolfcamp: 130 MBOE Drilling Cost: $0.9 MM / Well With Wolfcamp: $1.1 MM / Well Strong BTax returns at $60 / BOE IRR: 35%; DROI: 1.8 Cash margin: $45 / BOE Avg. Well Life: 35 Years Wolfcamp IP

Raton 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 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 Avg. Well Life: 35 Years 1) Reflects average EUR for 2004 - 2006 drilling program, which included a mix of initial wells in a section and infill drilling. Similar mix and EURs expected from 2007 program. Dewatering Period

Pawnee EURs Expected For Edwards Trend H1 10.2 8 H2 9.1 5 H3 8.4 1 H4 7.9 7 H5 4.8 15 H6 4.0 3 H7 4.0 2 H8 3.5 9 H9 1.8 3 H10 1.7 7 H11 0.0 3 0 0 5.263 2.467 5.428 2.829 2.138 4.441 3.125 2.796 2.796 0.789 0.263 0.083333333 0 4.052 2.274 5.328 2.78 1.898 2.813 2.885 1.82 2.133 0.723 0.203 0.166666667 0 3.489 2.137 5.229 2.733 1.727 2.225 2.679 1.487 1.746 0.671 0.161 0.25 0 3.151 2.034 5.133 2.687 1.602 1.906 2.504 1.303 1.501 0.63 0.132 0.333333333 2.896 1.948 5.039 2.642 1.497 1.679 2.347 1.172 1.313 0.594 0.109 0.416666667 2.706 1.877 4.946 2.598 1.412 1.518 2.208 1.079 1.171 0.564 0.092 0.5 2.556 1.816 4.855 2.556 1.34 1.396 2.085 1.007 1.06 0.538 0.078 0.583333333 2.434 1.764 4.765 2.514 1.279 1.3 1.975 0.95 0.971 0.516 0.068 0.666666667 2.331 1.718 4.677 2.473 1.226 1.221 1.876 0.902 0.898 0.496 0.059 0.75 2.243 1.678 4.591 2.433 1.18 1.155 1.787 0.863 0.836 0.478 0.052 0.833333333 2.166 1.641 4.507 2.395 1.139 1.099 1.706 0.828 0.783 0.462 0.046 0.916666667 2.099 1.608 4.424 2.357 1.102 1.05 1.631 0.798 0.737 0.447 0.041 1 2.039 1.578 4.342 2.32 1.068 1.007 1.563 0.772 0.697 0.434 0.037 1.083333333 1.985 1.55 4.262 2.284 1.038 0.969 1.501 0.748 0.662 0.422 0.033 1.166666667 1.936 1.525 4.184 2.249 1.01 0.935 1.443 0.727 0.63 0.411 0.03 1.25 1.891 1.501 4.107 2.214 0.985 0.905 1.389 0.707 0.602 0.401 0.028 1.333333333 1.85 1.479 4.031 2.18 0.961 0.877 1.34 0.69 0.577 0.391 0.025 1.416666667 1.812 1.458 3.957 2.147 0.939 0.851 1.293 0.674 0.553 0.382 0.023 1.5 1.777 1.439 3.884 2.115 0.919 0.828 1.25 0.659 0.532 0.374 0.021 1.583333333 1.745 1.421 3.812 2.084 0.9 0.807 1.21 0.645 0.513 0.366 0.02 1.666666667 1.714 1.404 3.742 2.053 0.882 0.787 1.172 0.632 0.495 0.359 0.018 1.75 1.686 1.388 3.673 2.023 0.866 0.768 1.137 0.62 0.479 0.352 0.017 1.833333333 1.659 1.372 3.605 1.994 0.85 0.751 1.103 0.609 0.464 0.345 0.016 1.916666667 1.634 1.358 3.539 1.965 0.835 0.735 1.072 0.598 0.449 0.339 0.015 2 1.61 1.344 3.474 1.937 0.821 0.72 1.042 0.588 0.436 0.333 0.014 2.083333333 1.588 1.331 3.41 1.909 0.808 0.706 1.014 0.579 0.424 0.327 0.013 2.166666667 1.566 1.318 3.347 1.882 0.795 0.692 0.987 0.57 0.412 0.322 0.012 2.25 1.546 1.306 3.285 1.856 0.783 0.679 0.962 0.562 0.401 0.317 0.012 2.333333333 1.526 1.294 3.225 1.83 0.771 0.667 0.938 0.554 0.391 0.312 0.011 2.416666667 1.508 1.283 3.165 1.805 0.76 0.656 0.915 0.546 0.382 0.308 0.01 2.5 1.49 1.272 3.107 1.78 0.75 0.645 0.893 0.539 0.372 0.303 0.01 2.583333333 1.473 1.262 3.05 1.755 0.74 0.635 0.872 0.532 0.364 0.299 0.009 2.666666667 1.457 1.252 2.994 1.732 0.73 0.625 0.852 0.525 0.356 0.295 0.009 2.75 1.442 1.243 2.938 1.708 0.721 0.616 0.833 0.519 0.348 0.291 0.008 2.833333333 1.427 1.233 2.884 1.686 0.712 0.607 0.815 0.513 0.34 0.287 0.008 2.916666667 1.412 1.224 2.831 1.663 0.704 0.598 0.798 0.507 0.333 0.284 0.008 3 1.398 1.216 2.779 1.641 0.696 0.59 0.781 0.501 0.327 0.28 0.007 3.083333333 1.385 1.208 2.728 1.62 0.688 0.582 0.765 0.496 0.32 0.277 0.007 3.166666667 1.372 1.199 2.677 1.599 0.68 0.574 0.75 0.491 0.314 0.274 0.007 3.25 1.36 1.192 2.628 1.578 0.673 0.567 0.735 0.486 0.308 0.271 0.006 3.333333333 1.348 1.184 2.58 1.558 0.666 0.56 0.721 0.481 0.303 0.268 0.006 3.416666667 1.336 1.177 2.532 1.538 0.659 0.553 0.707 0.476 0.297 0.265 0.006 3.5 1.325 1.17 2.486 1.518 0.652 0.547 0.694 0.472 0.292 0.262 0.006 3.583333333 1.314 1.163 2.44 1.499 0.646 0.54 0.682 0.467 0.287 0.259 0.005 3.666666667 1.304 1.156 2.395 1.48 0.639 0.534 0.67 0.463 0.282 0.257 0.005 3.75 1.293 1.149 2.351 1.462 0.633 0.528 0.658 0.459 0.278 0.254 0.005 3.833333333 1.283 1.143 2.307 1.444 0.627 0.523 0.646 0.455 0.273 0.251 0.005 3.916666667 1.274 1.137 2.265 1.426 0.622 0.517 0.635 0.451 0.269 0.249 0.005 4 1.264 1.13 2.223 1.408 0.616 0.512 0.625 0.447 0.265 0.247 0.004 4.083333333 1.255 1.125 2.182 1.391 0.611 0.507 0.615 0.444 0.261 0.244 0.004 4.166666667 1.246 1.119 2.142 1.375 0.606 0.502 0.605 0.44 0.257 0.242 0.004 4.25 1.238 1.113 2.103 1.358 0.6 0.497 0.595 0.437 0.253 0.24 0.004 4.333333333 1.229 1.108 2.064 1.342 0.595 0.492 0.586 0.433 0.25 0.238 0.004 4.416666667 1.221 1.102 2.026 1.326 0.591 0.487 0.577 0.43 0.246 0.236 0.004 4.5 1.213 1.097 1.988 1.31 0.586 0.483 0.568 0.427 0.243 0.234 0.004 4.583333333 1.205 1.092 1.952 1.295 0.581 0.478 0.56 0.424 0.24 0.232 0.004 4.666666667 1.198 1.087 1.916 1.28 0.577 0.474 0.551 0.421 0.236 0.23 0.003 4.75 1.19 1.082 1.881 1.265 0.573 0.47 0.543 0.418 0.233 0.228 0.003 4.833333333 1.183 1.077 1.846 1.25 0.568 0.466 0.536 0.415 0.23 0.226 0.003 4.916666667 1.176 1.072 1.812 1.236 0.564 0.462 0.528 0.412 0.228 0.225 0.003 5 1.169 1.067 1.779 1.222 0.56 0.458 0.521 0.409 0.225 0.223 0.003 5.083333333 1.162 1.063 1.746 1.208 0.556 0.455 0.514 0.407 0.222 0.221 0.003 5.166666667 1.156 1.058 1.714 1.194 0.552 0.451 0.507 0.404 0.219 0.219 0.003 5.25 1.149 1.054 1.682 1.181 0.548 0.447 0.5 0.401 0.217 0.218 0.003 5.333333333 1.143 1.05 1.651 1.168 0.545 0.444 0.493 0.399 0.214 0.216 0.003 5.416666667 1.136 1.045 1.621 1.155 0.541 0.44 0.487 0.396 0.212 0.215 0.003 5.5 1.13 1.041 1.591 1.142 0.537 0.437 0.481 0.394 0.209 0.213 0.003 5.583333333 1.124 1.037 1.561 1.13 0.534 0.434 0.475 0.392 0.207 0.212 0.002 5.666666667 1.119 1.032 1.533 1.117 0.531 0.431 0.469 0.389 0.205 0.21 0.002 5.75 1.113 1.028 1.504 1.105 0.527 0.428 0.463 0.387 0.203 0.209 0.002 5.833333333 1.107 1.024 1.477 1.093 0.524 0.425 0.457 0.385 0.2 0.207 0.002 5.916666667 1.102 1.019 1.45 1.082 0.521 0.422 0.452 0.383 0.198 0.206 0.002 6 1.096 1.015 1.423 1.07 0.518 0.419 0.446 0.381 0.196 0.205 0.002 6.083333333 1.091 1.011 1.397 1.059 0.514 0.416 0.441 0.379 0.194 0.203 0.002 6.166666667 1.086 1.007 1.371 1.048 0.511 0.413 0.436 0.377 0.192 0.202 0.002 6.25 1.08 1.003 1.346 1.037 0.508 0.41 0.431 0.374 0.19 0.201 0.002 6.333333333 1.075 0.998 1.321 1.026 0.505 0.408 0.426 0.373 0.188 0.2 0.002 6.416666667 1.07 0.994 1.296 1.015 0.503 0.405 0.421 0.371 0.187 0.198 0.002 6.5 1.066 0.99 1.273 1.005 0.5 0.402 0.417 0.369 0.185 0.197 0.002 6.583333333 1.061 0.986 1.249 0.994 0.497 0.4 0.412 0.367 0.183 0.196 0.002 6.666666667 1.056 0.982 1.226 0.984 0.494 0.397 0.407 0.365 0.181 0.195 0.002 6.75 1.051 0.978 1.204 0.974 0.492 0.395 0.403 0.363 0.18 0.194 0.002 6.833333333 1.047 0.974 1.181 0.964 0.489 0.392 0.399 0.361 0.178 0.193 0.002 6.916666667 1.042 0.97 1.16 0.955 0.486 0.39 0.395 0.36 0.176 0.192 0.002 7 1.038 0.966 1.138 0.945 0.484 0.388 0.391 0.358 0.175 0.19 0.002 7.083333333 1.034 0.962 1.117 0.936 0.481 0.386 0.386 0.356 0.173 0.189 0.002 7.166666667 1.029 0.958 1.097 0.926 0.479 0.383 0.383 0.355 0.172 0.188 0.002 7.25 1.025 0.954 1.076 0.917 0.477 0.381 0.379 0.353 0.17 0.187 0.002 7.333333333 1.021 0.95 1.057 0.908 0.474 0.379 0.375 0.351 0.169 0.186 0.001 7.416666667 1.017 0.946 1.037 0.899 0.472 0.377 0.371 0.35 0.167 0.185 0.001 7.5 1.012 0.942 1.018 0.891 0.469 0.375 0.368 0.348 0.166 0.184 0.001 7.583333333 1.008 0.938 0.999 0.882 0.467 0.373 0.364 0.347 0.165 0.183 0.001 7.666666667 1.004 0.934 0.981 0.873 0.465 0.371 0.36 0.345 0.163 0.182 0.001 7.75 1 0.93 0.963 0.865 0.463 0.369 0.357 0.344 0.162 0.182 0.001 7.833333333 0.996 0.926 0.945 0.857 0.461 0.367 0.354 0.342 0.161 0.181 0.001 7.916666667 0.991 0.922 0.928 0.849 0.458 0.365 0.35 0.341 0.159 0.18 0.001 8 0.987 0.918 0.911 0.841 0.456 0.363 0.347 0.339 0.158 0.179 0.001 8.083333333 0.983 0.915 0.894 0.833 0.454 0.361 0.344 0.338 0.157 0.178 0.001 8.166666667 0.979 0.911 0.877 0.825 0.452 0.359 0.341 0.337 0.156 0.177 0.001 Years MMCFPD Pawnee gross reserves from 63 horizontal wells Typical well EUR of 3.5 BCF Edwards development program being modeled from Pawnee 3.5 BCF horizontal well 3-D seismic being shot to optimize drilling locations Strong BTax Returns @$7.50/MCF IRR: 45%, DROI: 2.2 Working Interest: 80% to 100% Net Revenue Interest: 65% to 80% Drilling Cost: $3.5 MM / Well Avg. Well Life: 35 Years Edwards Modeling1 1) Modeling reflects geologic similarities between Pawnee and Edwards Trend prospects Type Curve EUR (BCF) # of wells

2007 - 2011 Maintenance Capital Requirements 1) PDP production declines ~ 7% excluding VPP volumes 2) Excludes facilities and other maintenance capital of ~ $50 MM per year PDP production declines ~9% per year1 ~ $0.5 B per year required to maintain flat production Date PDP Production (MBOED) VPP Volume (MBOED) Development Drilling Adds (MBOED) Total Production (MBOED) # of Spraberry Wells # of Raton Wells CapEx2 ($MM) 2007 88 15 8 111 300 156 360 2008 81 13 17 111 312 156 370 2009 74 12 25 111 319 163 380 2010 72 7 32 111 324 168 390 2011 68 4 39 111 336 168 400 PDP Production 2009 Dev. Drilling VPP Volume 2010 Dev. Drilling 2007 Dev. Drilling 2011 Dev. Drilling 2008 Dev. Drilling 150 125 100 75 50 25 Production (MBOED)

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 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 5.99 6.53 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 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 1.25 1.22 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 3.2 2.29 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 0.92 0.48 Production Costs (per BOE) Production & Ad Valorem Taxes Q 1 2006 Q 2 2006 $11.04 $2.96 $1.21 $0.72 Q 3 2006 $6.15 Note: All periods presented have been restated to exclude discontinued operations VPP-Adjusted $9.89 $9.47 $9.84 Workovers LOE Transportation Q 4 2006 $11.45 $3.28 $1.20 $0.74 $6.23 $5.18 Production Cost LOE $11.36 $3.20 $1.25 $0.92 $5.99 $5.28 $5.38 $10.52 $2.29 $1.22 $0.48 $6.53 $9.14 $5.67

2006 Production Cost vs. Peers PXD 9.59 1.5 NBL 6.71 CHK 6.91 EOG 7.2 RRC 7.61 NFX 8.36 XTO 9.29 APA 10.51 XEC 10.58 KWK 10.85 PPP 11.26 PXP 14.49 $ / BOE 11.09 6.71 6.91 7.20 7.61 8.36 9.29 14.49 11.26 10.58 10.51 2006 Average (9.43) 9.59 if VPP Volumes Added Sources: Bear Stearns & Company financials 1.50 10.85

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: Q1 '06 Q2 '06 Q3 '06 Q4 '06 Production costs as reported (thousands): LOE $ 52,735 $ 56,071 $ 54,266 $ 60,505 Total $ 94,683 $103,065 $102,970 $ 97,539 Production (MBOE): As reported 8,573 8,999 9,064 9,274 VPP deliveries 1,421 1,419 1,402 1,395 VPP-adjusted production 9,994 10,418 10,466 10,669 Production costs per BOE: As reported: LOE $ 6.15 $ 6.23 $ 5.99 $ 6.52 Total $ 11.04 $ 11.45 $ 11.36 $ 10.52 VPP-adjusted: LOE $ 5.28 $ 5.38 $ 5.18 $ 5.67 Total $ 9.47 $ 9.89 $ 9.84 $ 9.14

Approximate based on historical differentials to index prices % of production Gas Apr - Dec 2008 2009 Swaps - (MMBTUD) 225,000 15,000 - NYMEX Price ($/MMBTU)1 $ 8.48 $9.10 - % Hedged N American Gas2 60% 4% - Crude Swaps - Old (BPD) - 4,000 - NYMEX Price ($/BBL) - $32.00 - Swaps - New (BPD) - 5,000 NYMEX Price ($/BPL) - $69.84 Collars - New (BPD) 4,455 - - NYMEX Call Price ($/BPL) $76.04 - - NYMEX Put Price ($/BPL) $63.00 - - % Hedge Total Liquids2 10% 19% - Total Equivalent % Hedged Total Equiv.2 39% 10% - Hedge Position as of 4/02/2007 HEDGING STRATEGY Capture Spikes Protect Capital Budget and Project Economics

Pro Forma Senior Notes and Credit Facility 2006 2007 2008 2009 2010 2011 2012 2028 $32 MM 8.25% $6 MM 5.875% $250 MM 7.20% 2016 $527 MM 5.875% 2018 $450 MM 6.875% $126 MM $1.5 B Credit Facility ($1.4 B extended to 2011) $4 MM 6.50% Maturities and Balances as of 03/07/2007 2017 $500 MM 6.65%

Met 2006 F&D and Reserves Goals Reported audited year-end proved reserves of 905 MMBOE Added 91 MMBOE Additions primarily in Spraberry, Raton, Edwards Trend and Canada 89% of reserves audited by Netherland, Sewell and Associates, Inc. Reserve mix 98% North America 54% gas / 46% oil 60% PDP / 40% PUD All-in finding and development cost of $18.36 / BOE ~$15 / BOE for reserves added in lower 48 & Canada where production grew 12% in '06 Reserves / Production Ratio - 20+ years Year-end '06 Proved Reserves (MMBOE) Resource Potential* (MMBOE) Permian 452 120 Mid-Continent 113 0 Rockies 260 190 Gulf Coast 30 170 Alaska 0 120 Canada 31 60 Africa 19 50 Other 0 40 Total 905 ~750 * Excludes high-impact exploration

Historical Spraberry F&D - Consistently Attractive 2001 2001 2001 2002 2003 2004 2005 2006 Capital ($MM) Capital ($MM) 128 128 128 26 70 72 275 360 Development & Exploration Development & Exploration 36 36 36 26 57 48 125 280 Acquisitions Acquisitions 92 92 92 0 13 24 150 80 # Wells Drilled # Wells Drilled 100 100 100 85 119 117 188 300 Reserves Added (MMBOE) 8 8 8 103 103 46 26 83 45 Extensions & Discoveries Extensions & Discoveries Extensions & Discoveries 0 0 0 0 0 0 6 Acquisitions Acquisitions Acquisitions 29 29 0 6 15 78 49 PDP PDP PDP 29 29 0 1 4 7 3 PUD PUD PUD 0 0 0 5 11 71 46 Revisions Revisions Revisions -21 -21 103 40 11 5 -10 F&D ($ / BOE) F&D ($ / BOE) F&D ($ / BOE) All-in F&D (including revisions) All-in F&D (including revisions) All-in F&D (including revisions) 16.00 16.00 0.25 1.52 2.77 3.31 8.00 Organic F&D (including revisions) Organic F&D (including revisions) Organic F&D (including revisions) ^ ^ ^ ^ ^ ^ 46.67 Acquisitions Acquisitions Acquisitions 3.17 3.17 0.00 2.17 1.60 1.92 1.63 All-in F&D ($/BOE) 2001 - 2006: ~$3 Current: ~$11

Finding and Development Costs "All-in F&D 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 mineral-in-place and discoveries and extensions. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. "Organic F&D costs per BOE" means costs incurred excluding acquisitions divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, 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 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", "reserve potential", "future reserve adds", "estimated ultimate recovery (EUR)", "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.