8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): January 13, 2009

PIONEER NATURAL RESOURCES COMPANY

(Exact name of Registrant as specified in its charter)

Delaware	1-13245	75-2702753
(State or other jurisdiction of incorporation or organization)	(Commission File Number)	(I.R.S. Employer Identification No.)
5205 N. O’Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

(972) 444-9001

(Registrant’s telephone number, including area code)

Not applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

PIONEER NATURAL RESOURCES COMPANY

Item 2.02. Results of Operations and Financial Condition.

     Pioneer Natural Resources Company (the “Company”) hereby furnishes the portions, if any, of the presentation filed as Exhibit 99.1 to this report (the “Presentation”) that constitute material non-public information regarding the Company’s results of operations or financial condition for a completed quarterly or annual period.

Item 7.01. Regulation FD Disclosure.

     The Company will post the Presentation on the Company’s website, www.pxd.com. The Presentation can be reviewed at the website by first selecting “Investors,” then “Investor Presentations.”

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

99.1 Investor Presentation — January 2009

SIGNATURE

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

PIONEER NATURAL RESOURCES COMPANY
By:	/s/ Frank Hall
	Frank Hall,
	Vice President and Chief Accounting Officer

Dated: January 13, 2009

PIONEER NATURAL RESOURCES COMPANY

EXHIBIT INDEX

Exhibit No.	Description
99.1(a)	Investor Presentation — January 2009

(a) Furnished herewith.

EX-99.1

Exhibit 99.1

Investor Presentation January 2009

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, the ability to obtain approvals from third parties and negotiate agreements with third parties on acceptable terms, 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, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add 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 Low-decline assets attractive in current low commodity price environment and performing above expectations Large resource potential Strong financial flexibility Delivering free cash flow1 in 2009 and beyond Taking prudent and decisive steps to reduce costs and improve returns in current environment Will increase drilling activity when we have confidence in sustained commodity prices above $60 oil / $7 gas, coupled with an additional 10% - 20% well cost reduction from current levels DCF in excess of capital expenditures

Low-Decline Assets Attractive in Current Environment Strong 2008 production growth performance (+18% 9 Mo.'08 vs. 9 Mo.'07)1 Driven by core assets +23% (includes Spraberry, Raton, Edwards, Tunisia and Alaska) Over 20,000 drilling locations Upside from new shale plays (Pierre, Spraberry, Barnett and Eagle Ford) Minimal capital needed (~$200 MM) to keep annual production flat in 2009 Highlights attractiveness of low-decline assets with long R/P ratio Includes production attributable to the public ownership in PSE; pro forma for Canada divestiture

Consistent Production Growth Driven by Low-Risk Drilling1 MMBOE Production pro forma for Deepwater GOM, Argentina and Canada divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005; includes production attributable to the public ownership in PSE beginning in May 2008 2005 2006 2007 2008 2009 2010 2011 Historical Production Production Outlook 30.9 33 36 42 43 53 62 1 1 7 7 33 31 Per Share CAGR: 17% 36 41 - 42 Forecasting Increase of 5+% Per Share vs. 2008 In Low Commodity Price Environment Forecasting Increase of ~20% Per Share vs. 2007

Spraberry Historical IRRs Typically Average 35% - 40% Reductions in well costs are needed to generate attractive returns 2005 2006 2007 2008 AVG Nov. '08 Future Well Cost 0.7 0.9 1.1 1.3 1.4 1 Returns 40 40 35 60 20 40 Oil Price 57 66 72 115 60 60 Well Cost ($MM) Oil Price ($/BBL) IRR Before Tax All PXD assets have seen similar cost escalations and erosion of returns in the recent commodity price downturn

Large Resource Potential1 YE '06 Proved Reserves (MMBOE) YE '07 Proved Reserves (MMBOE) Additional Net Resource Potential (MMBOE) Spraberry 440 4812 1,000 Raton CBM/Pierre Shale 250 266 350 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 2007 pricing of $95.92/BBL and $6.80/MMBTU (NYMEX) Includes proved reserves attributable to the public ownership in PSE Pro forma for Canada divestiture 2.8 BBOE of Proved Reserves and Resource Potential

Strong Financial Flexibility 2008 2009 2010 2011 2012 2016 $6 MM 5.875% $250 MM 7.20% 2017 $527 MM 5.875% 2028 $450 MM 6.875% $679 MM2 of $1.5 B Credit Facility Maturities and Balances1 2018 $500 MM 6.65% As of 9/30/08 Net debt: $2.8 B Net debt to book capitalization: 44% Credit facility availability: $775 MM Excludes net discounts and hedge losses of ~$89 MM Excludes ~$46 MM of outstanding letters of credit During January 2008, Pioneer issued $500 MM of 2.875% convertible senior notes due 2038, with a first put/call in 2013 2013 $500 MM3 2.875% Credit facility does not mature until 2012 No significant bond maturities until 2013 Significant capacity under covenants Targeting 35% - 40% net debt to book capitalization

Plan To Deliver Free Cash Flow In 2009 And Beyond Implementing capital spending cuts and cost reduction initiatives to ensure free cash flow during commodity price downturn Decreasing drilling activity until prices, gas differentials and well costs improve Initial annual capital spending run-rate of ~$350 MM1 Reducing operating costs and G&A Free cash flow uses: Debt reduction Opportunities to purchase debt significantly below carrying value Share repurchases Repurchased 37.5 MM shares between Q4 2004 and October 2008, or 26% of shares outstanding $420 MM remaining under current authorization Bolt-on acquisitions Capital spending excludes acquisitions, ARO, capitalized interest and G&G G&A

Spraberry - Solid Production Growth Q3 '08 production: 30 MBOEPD1 +10% vs. Q3 '07 2008 production growth target: 15%1 Drilled 370 wells in 2008 2009 drilling program curtailed until conditions improve Includes production attributable to the public ownership in PSE beginning in May 2008 Source: Energy Information Administration 9 mo '07 9 mo '08 2005 2006 2007 2008 2009 2010 2011 26 30 20 23.581 26.6 31 44 1 3.5 MBOEPD1 24 27 '06 '07 '08 20 '05 15% 9 MOs '07 30 26 9 MOs '08 17% Spraberry: 5th largest U.S. oil field2

50/6 60/6 75/7.50 Current 20 25 40 Targeted 30 40 60 Spraberry 40-acre Drilling Returns (EUR: 100 MBOE) Expected Well Cost1 ($0.8 MM) Current Well Cost2 ($1.0 MM) 1) Expected returns assume approximately 33% reduction in well cost vs. Q3 2008 cost of $1.2 MM 2) Current returns reflect well cost reductions to date of 17% vs. Q3 2008 cost of $1.2 MM Pioneer is low-cost driller in Spraberry, benefiting from integrated service model 35% 35%+ IRR threshold to increase drilling activity

Spraberry - Continuing to Progress Resource Initiatives Ongoing 40-acre field development 200 20-acre spacing 500 Drilled 18 20-acre wells in 2008 with encouraging results Waterflood 300 Identified 6,000-acre area under existing unit for project in 2009/2010 Total 1,000 Additional upside potential Shale/silt non-traditional intervals Initial 650 feet core analysis indicates that up to 30 feet of additional pay is present Testing approximately 20 BOEPD stabilized rates from isolated zones Horizontal drilling Five re-entries have averaged >6 fold production increase after stimulation Deeper Zones Wolfberry and deeper horizons Additional Net Resource Potential (MMBOE) Goal: Increase recovery per section from 12% - 13% to 27% - 28% or greater

Wolfberry Proven play with robust well performance EURs of 120 - 150 MBOE Large inventory including several hundred drillable locations Significant portion of future drilling programs Recent Pioneer wells with IPs > 100 BOEPD IPs > 100 BOEPD Wolfberry Trend Wolfberry Trend

Wolfberry 40-acre Drilling Returns (EUR: 120 - 150 MBOE) 50/6 60/6 75/7.50 Current 32 45 70 Expected 53 70 100 Target Well Cost1 ($1.0 MM) Current Well Cost2 ($1.2 MM) 1) Target returns assume approximately 33% reduction in well cost vs. Q3 2008 cost of $1.5 MM 2) Current returns reflect well cost reductions to date of approximately 20% vs. Q3 2008 cost of $1.5 MM 35% 35%+ IRR threshold to increase drilling activity

Raton CBM and Pierre Shale - Solid Production Growth Q3 '08 production: 195 MMCFPD +12% vs. Q3 '07 2008 production growth target: >15% Drilled 155 wells in 2008 146 CBM wells and 9 Pierre Shale wells Vertical Pierre Shale performance continues to improve in Kp1 - Kp3 zones 2 horizontal Pierre Shale wells drilled and completed to assess upside Formation image logs show very high frequency of natural fractures in both 2,000' laterals 2009 drilling program curtailed until conditions improve 9 MOS '07 9 Mos '08 2005 2006 2007 2008 0 0 2011 165 198 142 155 171 198 268 10 50 MMCFPD '06 '07 '08 155 171 142 '05 >15% 9 MOs '07 9 MOs '08 1652 1983 20% Source: Energy Information Administration Q1 '07 production impacted by weather-related losses 9 Months '08 benefited from Q4 '07 acquisition (10 MMCFPD)

6 7 8 Current 25 35 45 Expected 35 35 45 Raton CBM Drilling Returns (EUR: 0.7 BCF) Current Well Cost ($0.475 MM) Raton CBM well cost did not experience significant escalation during commodity price run-up, benefiting from integrated well service model 1) Approximate Mid-Continent differentials of $1.30 vs. NYMEX 35% 35%+ IRR threshold to increase drilling activity

Edwards Trend Delivering Strong Production Growth Q3 '08 production: 78 MMCFPD +26% vs. Q3 '07 2008 production growth target: >40% Net production recently increased to >80 MMCFPD with the addition of new treating capacity New discovery: 25 BCF of additional resource potential Drilled 36 wells in 2008 2009 drilling program curtailed until conditions improve >900 sq mi 3-D seismic shoot complete ~310 M gross acres 9 Mos '07 9 Mos '08 2005 2006 2007 2008 51 73 40 39 53.7 70 6 MMCFPD '06 '07 '08 39 54 40 >40% '05 51 73 9 MOs '07 9 MOs '08 44%

Edwards Drilling Returns (EUR: 3.5 BCF) 6 7 8 Current 30 50 70 Expected 40 60 90 Expected Well Cost1 ($4.1 MM) Current Well Cost2 ($4.5 MM) 1) Expected returns assume approximately 25% reduction in well cost vs. Q3 2008 cost of $5.5 MM 2) Current returns reflect well cost reductions to date of 18% vs. Q3 2008 cost of $5.5 MM 35% 35%+ IRR threshold to increase drilling activity

50 miles Eagle Ford Shale Activity in South Texas Bee Goliad Live Oak Karnes McMullen LaSalle Atascosa Wilson Bexar Guadalupe Gonzales Dewitt Lavaca Colorado Fayette Caldwell Edwards shelf margin Edwards Field Pioneer Eagle Ford activity Pioneer acreage (310,000 acres) Petrohawk Eagle Ford activity Pioneer drilling first Eagle Ford horizontal well Petrohawk expected January completion Petrohawk gas discovery 9.1 MMCFEPD IP Eagle Ford Shale overlays the Edwards Trend in all of Pioneer's 310,000 acres Petrohawk Q4 spud

Tunisia 2005 2006 2007 2008 4.521 6.09 2.585 2.585 4.264 8.1 0 1 Liftings1 (MBOEPD) '07 '08 3 4 50% - 60% 3 '05 9 MOs '07 9 MOs '08 6 '06 Proposed Gas Pipeline (200 miles) Cherouq ~3 MM gross acres in Tunisia Highest drilling returns in Company 10 operated discoveries through Q3 2008 Drilling curtailed until new 3-D seismic is fully processed Total net production from Cherouq, Adam and BEK currently 7.5 MBOEPD FEED study with other industry players underway for gas pipeline from southern Tunisia to northern industrial areas 1) Net reported production will vary from field production based on lifting schedules 4

South Africa Production Expected To Increase 50% In 2009 Net production 3.8 MBOEPD in Q3 Included production from Sable oil field and initial South Coast Gas (SCG) wells (gas and condensate) Production from most prolific SCG well on stream ahead of schedule Gross SCG production currently ~70 MMCFEPD; expected to gradually increase to 80 - 90 MMCFEPD in early 2009 (no capital required) Total net production (45% WI) of gas and liquids from SCG expected to average 20 - 25 MMCFEPD in Q4 and 30 - 35 MMCFEPD during 2009 LOE expected to decrease from ~$30/BOE to <$5/BOE 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

Alaska Oooguruk Net production achieved targeted year-end 2008 exit rate of >3 MBOPD Net production expected to average 5 MBOPD in 2009 and gradually increase to 10 - 14 MBOPD in 2011 as development drilling continues Net resource potential: 70 - 90 MMBO Cosmopolitan Permitting and FEED study for facilities underway Expect to drill next well in 2010 Net resource potential: 30 - 50 MMBO Cosmopolitan Discovery PXD 100% WI (Operator) Oooguruk Project PXD 70% WI (Operator)

Investment Highlights Low-decline assets attractive in current low commodity price environment and performing above expectations Large resource potential Strong financial flexibility Delivering free cash flow1 in 2009 and beyond Taking prudent and decisive steps to reduce costs and improve returns in current environment Will increase drilling activity when we have confidence in sustained commodity prices above $60 oil / $7 gas, coupled with an additional 10% - 20% well cost reduction from current levels DCF in excess of capital expenditures

Appendix

Pioneer Operations

Credit Facility Capacity as of 9/30/08 Tranche loans: $679 MM ($400 MM fixed at ~2.9%) Letters of Credit: $46 MM Capacity: $775 MM $1.5 B Credit Facility Credit facility financial covenants Debt to Book Capitalization < 60% PV to Total Debt > 1.75x Total Indebtedness as of 9/30/08 Net long-term debt is ~$2.8 B Average interest rate at 5.5%

Credit Facility Counterparties Lender Commitment Applicable Percentage Bank of America $117 MM 7.8 % Deutsche Bank $117 MM 7.8 % Wachovia $117 MM 7.8 % Wells Fargo Bank $117 MM 7.8 % JPMorgan Chase Bank $ 92 MM 6.1 % DnB NOR Bank $ 80 MM 5.3 % UBS $ 80 MM 5.3 % BMO $ 65 MM 4.3 % Calyon $ 65 MM 4.3 % The Royal Bank of Scotland $ 65 MM 4.3 % Bank of Tokyo Mitsubishi $ 65 MM 4.3 % The Bank of Nova Scotia/Scotiabank Inc. $ 65 MM 4.3 % BNP Paribas $ 50 MM 3.3 % Compass Bank $ 50 MM 3.3 % Mizuho Corporate Bank $ 50 MM 3.3 % Barclays $ 40 MM 2.7 % Citibank $ 40 MM 2.7 % Fortis Bank $ 40 MM 2.7 % Societe Generale $ 40 MM 2.7 % Toronto Dominion (Texas) $ 40 MM 2.7 % US Bank $ 40 MM 2.7 % Union Bank of California $ 30 MM 2.0 % Credit Suisse $ 25 MM 1.7 % Goldman Sachs $ 10 MM 0.7 % Total $ 1,500 MM

2005 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 Q1 2008 Q2 2008 Q3 2008 East 85 90 89 96 101 103 110 114 112 4 Production Growth History 1) Production pro forma for Deepwater GOM, Argentina and Canada divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005; includes production attributable to the public ownership in PSE since PSE IPO in Q2 '08 2) Q1 '07 production impacted by weather-related losses in Raton, Mid-Continent and Spraberry totaling ~3 MBOEPD 3) Q3 '08 production impacted by hurricane-related losses in Spraberry, Barnett, South Texas and GOM Shelf (~3 MBOEPD) Q3 '08 production +11% vs. Q3 '07 9 Months '08 production +18% vs. 9 Months '07 90 103 892 2006 Q2 '07 MBOEPD1 Q1 '07 Q3 '07 96 101 Q4 '07 85 2005 Q2 '08 110 114 Q1 '08 112 Q3 '08 1153 Hurricane Losses

Production (MBOEPD)1 Q3 '07 Q4 '07 Q1 '08 Q2 '08 Q3 '08 Spraberry 27 28 30 312 302,3 Raton 29 31 33 33 33 Edwards 10 10 12 12 13 Mid-Continent 22 20 20 20 19 Other U.S. 6 6 7 7 6 Total N. America 94 95 102 103 101 Tunisia 5 3 4 7 7 S. Africa 2 5 4 4 4 Total 101 103 110 114 112 1) Restated to exclude Canada discontinued operations 2) Includes production attributable to the public ownership in PSE 3) Reduced by ~2.5 MBOEPD due to curtailed or shut-in production from hurricane impacts on Gulf Coast fractionation facilities

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 2) Offshore Oil Field - -5% Spraberry is 5th largest oil field and 15th largest gas field in the U.S.1

PXD - Largest Spraberry Trend Producer Gross operated production ~50 MBOEPD1 Represents ~40% of total Spraberry production Net production ~39 MBOEPD1 YE 2007 proved reserves of 481 MMBOE 2 (~50% PDP / ~50% PUD) 869,000 acres (~50% of Spraberry field) 5,300 active wells (>95% operated) Average working interest: 90% Spraberry oil receives up to $0.50 / Bbl premium to WTI 1,400 BTU gas; high NGL yield Low-cost driller and operator 27% ownership interest in Midkiff-Benedum midstream facilities Option to acquire additional 22% in 2009 At June 30, 2008. Includes Spraberry VPP volumes of 8 MBOEPD Includes proved reserves attributable to the public ownership in PSE Midland (869,000 gross acres) PXD Acreage 150 miles 75 miles Third Party Acreage Midland

Spraberry 20-Acre Spacing Spraberry 20-Acre Spacing 5 10 15 20 25 Average Working Interest: ~90% Average Net Revenue Interest: ~75% Gross EUR: 100 MBOE Expected Average Well Life: 35 Years 20-Acre Well Early projection of type curve based on actual results OIL NGL GAS Railroad Commission of Texas approved field rule change to allow optional 20-acre downspacing field-wide Approximately 9,500 20-acre drilling locations identified Historical downspacing performance (160-acre to 80-acre to 40-acre) suggests reserves from a 20-acre well will be at least 75% to 80% of a 40-acre well Expect similar returns to 40-acre wells Production from 20-acre wells drilled in 2008 supports this conclusion 40-Acre Well

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 Niobrara Dakota Current Production (Kp1, Kp2 and Kp3) Prospective Producing Zones (Kp4 and Kp5)

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 Avg. Working Interest: ~96% Avg. Net Revenue Interest: ~84% Mean EUR (Gross): 0.7 BCFE Expected Avg. Well Life: 35 Years Dewatering Period

Pierre Shale Type Curve 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 155 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 135 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 24 months and the other 18 months

Barnett Shale Expansion / Tier 2 Area 16 MMBOE proved reserves YE '07 Multi-year drilling inventory >450 2P locations 90 MMBOE additional net resource potential Acquired Dune Energy's Barnett assets in Denton and Wise Counties during Q3 2008 for $38 MM Proved reserves: 6.1 MMBOE Acreage: 4,000 acres Drilling locations: 30 Current production: 6 MMCFEPD 2009 drilling program curtailed until conditions improve Tier 1 Core Ft. Worth PXD built ~80 M gross acreage position in 2007

By the end of 2012, the entire VPP commitment will expire and provide a 13 MBOEPD increase in production with no capital requirement The expiration of the VPP commitment and legacy hedges (year-end 2008) significantly improves cash flow 2008 2009 2010 2011 2012 2013 Historical Production VPP Oil 8 7 7 4 4 0 VPP Gas 5 5 Legacy Hedges 10 1 6 9 9 13 Declining VPP Commitments Increase Production 6 1 9 9 Production Growth From VPP Expirations (MBOEPD vs. 2008) 8 13

Maintenance capital requirement only $200 MM in both 2009 and 2010 Keeps production flat Maintains drilling in Alaska Maintains acreage leasehold 2009 production growth benefits from startup of most prolific South Coast Gas well in Q4 '08, late 2008 infrastructure adds in Edwards and 1,000 BOEPD of reduced VPP commitment 2010 production growth benefits from 5,000 BOEPD of reduced VPP commitment Significant growth from Alaska in 2009 and 2010 After 2010, need to invest approximately $500 MM - $600 MM to maintain annual production levels Minimal Maintenance Capital Requirements in 2009 / 2010 Highlights attractiveness of low-decline assets with long R/P ratio

Op Cost G&A Interest DD&A PXD 14.1 3.38 3.69 11.46 PXD VPP-Adjusted 12.64 3.03 3.31 10.27 PEER AVG 11.41 3.02 2.33 14.01 CS Universe 12.71 4.27 3.19 14.94 9 Months 2008 All-in Costs vs. Peers 9 Months 2008 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 Credit Suisse Universe consists of 38 E&P companies $32.63 Op Cost $35.11 2 G&A DD&A Interest $29.25 (excludes capitalized G&A)

All-In Finding and Development Costs ($ / BOE) 2007 2002-2007 Average PXD 15.4 12.44 CS Universe 16.79 14.53 PXD CS UNIVERSE1 Source: Credit Suisse; CS Universe consists of 54 E&P companies PXD CS UNIVERSE1 2007 All-in F&D Costs ($ / BOE)

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," "net resource potential," "EUR," "OOIP" 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.

Finding & Development Costs "Finding and development costs per BOE," "F&D per BOE," or "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 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.