Pioneer Natural Resources (PXD) 8-K Results of Operations and Financial Condition

Exhibit 99.1

Forward-Looking Statements Except for historical information contained herein, the statements, charts and graphs included in this exhibit to the Company's Current Report on Form 8-K 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, availability of drilling equipment, Pioneer's ability to replace reserves, implement its business plans (including its plan to repurchase stock and its plan to form Pioneer Southwest Energy Partners L.P. and offer securities representing interests therein) 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, 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 a impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.

Finding & Development Costs and Reserve Replacement "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. "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. "Reserve replacement" is 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 divided by annual production of oil, NGLs and natural gas, on a BOE basis.

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 included in this exhibit to its Current Report on Form 8-K, such as "estimated", "resource potential", "reserve potential", "2P", "estimated ultimate recovery (EUR)" or other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques 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, and in our Current Report on Form 8-K filed with the SEC on January 14, 2008, file No. 1-13245, and available from us at Investor Relations, 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039. You can also obtain these forms from the SEC by calling 1-800-SEC-0330.

A registration statement relating to the common units of Pioneer Southwest Energy Partners L.P. has been filed with the Securities and Exchange Commission but has not yet become effective. These securities may not be sold, nor may offers to buy be accepted, prior to the time the registration statement becomes effective. This exhibit to the Company's Current Report on Form 8-K does not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of these securities in any state in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any such state or jurisdiction. The offering of common units will be made only by means of a prospectus. A copy of the prospectus, when available, may be obtained by submitting requests to Citigroup Global Markets Inc., Attention: Prospectus Department, Brooklyn Army Terminal, 140 58th Street, 8th Floor, Brooklyn, New York 11220, phone: 718-765-6732, fax: 718-765-6734; Deutsche Bank Securities Inc., Attention: Prospectus Department, 100 Plaza One, Jersey City, New Jersey 07311, phone: 800-503-4611, or email: prospectusrequest@list.db.com; or UBS Securities LLC, Attention: Prospectus Department, 299 Park Avenue, New York, New York 10171, phone: 212-821-3000.

Spraberry Resource Play - Cornerstone of Growth Production increased 14% vs. Q3 2006 and 12% vs. 9 months 2006 Expected to grow 10% - 15% in 2008 after the effects of PSE IPO2 Continuing to pursue acreage expansion and bolt-on acquisitions $90 MM Q4 '07 bolt-on acquisition added 38 MMBOE resource potential Drilled ~350 wells in 2007, with a similar drilling program expected in 2008 Continuing to drill to deeper Wolfcamp zone where incremental reserves and production of >20% being added to typical Spraberry well 869 M gross acres 4,800 active wells (>95% operated) Largest operator ~30% of Total Production ~50% of 2006 Total Proved Reserves1 440 MMBOE - 50% PDP / 50% PUD Multi-year Drilling Inventory ~4,600 2P Locations (40-acre spacing) Q1 Q2 Q3 2006 2007 2008 25 26 27 24 26.5 29.1 1.2 2.88 MBOEPD 27 24 '06 25 26 '07 '082 Q1 Q2 2007 10%-15% 10%-15% Q3 Pro forma for the divestiture of Canada Net of production estimated to be attributable to public unitholders following the IPO of PSE

Edwards Trend Production Growing Production increased 63% vs. Q3 2006 and 31% vs. 9 months 2006 Expected to grow >30% in 2007 and ~25% in 2008 Two new fields discovered in Q3 bringing total in the expansion area to eight Drilled ~35 wells in 2007 (primarily development wells), with a similar drilling program expected in 2008 Multiple isolation packer frac technology increasing average EUR of ~3.5 BCF by 1.0 - 1.5 BCF Proppant fracs of existing horizontal wells at Pawnee continuing to show success EURs increased by average 1.0 - 1.5 BCF per well Progressing >900 sq mi 3-D seismic surveys and infrastructure expansion (treating and pipelines) Q1 Q2 Q3 2006 2007 2008 43 48 62 39.4 53.2 63.8 2 3 ~300 M gross acres MMCFEPD 62 39 30+% '06 43 '07 '08 Q1 Q2 2007 48 ~25% Q3

Q1 Q2 Q3 2006 2007 2008 152 169 174 155 167 184 3 3 Raton Growth Continues New Mexico Colorado Raton 310 M gross acres Receives Mid- Continent Prices MMCFEPD Production increased 11% vs. Q3 2006 and 8% vs. 9 months 2006 Expect to grow 8% - 10% in 2007 and ~10% in 2008 Q1 '07 weather disruptions negatively impacted 2007 production Mid-Continent pricing Improved drilling and completions efficiencies allowed ~300 new wells to be brought online during 2007 Expect to drill ~150 wells during 2008 $205 MM Q4 '07 bolt-on acquisition added 124 BCF resource potential Integrated well services continue to mitigate cost creep Adding wellhead compression throughout field and optimizing field pressures CIG Pipeline ~30% of Total Production ~30% of 2006 Total Proved Reserves1 250 MMBOE - 60% PDP / 40% PUD 3 - 4 Year Drilling Inventory ~1,200 2P Locations 155 '06 152 169 '07 '082 Q1 Q2 2007 8%-10% ~10% 174 Q3 Pro forma for the divestiture of Canada Excludes production from Q4 '07 acquisition

Barnett Shale Goal: Build a Core Position Expansion / Tier 2 Area Tier 1 Core Ft. Worth 15 Q4 Acquisition: Purchase price: $150 MM ~37,000 gross acres, predominantly Parker County (70% WI) >300 drilling locations; most covered by 3-D seismic 480 BCFE resource potential ~80 BCFE proved Current net production: ~15 MMCFEPD Additional ~37,000 gross acres in expansion areas Expect to ramp up drilling in 2008 Purchase structured as part of a like-kind exchange to defer a majority of PXD's tax liability on the expected sale of Spraberry assets to Pioneer Southwest Energy Partners L.P. Existing Operations: 13,000 gross acres with >150 drilling locations Participated with Devon (50% WI) in 5 successful wells to date in Wise County PXD Existing Acreage New Acquisition

Q1 Q2 Q3 Q1 Q2 4 5 5 0 3 4.6 8 1 1 Tunisia Success Continues Production essentially doubled vs. Q3 2006 and vs. 9 months 2006 Production expected to grow 90+% in 2008 Jenein Nord 7 discoveries since late 2006 Constructing production facilities Initial capacity of 10 MBOPD expanding to 20 MBOPD during 2H 2008 Production commenced late Q4 2007 and will gradually increase during 2008 as wells tied in Additional 3-D seismic acquisition underway Adam Recent discovery tested ~4 MBOPD; expected to be on production in January Anaguid Initial 3-D seismic acquisition planned for 2008 Expect to drill 15 - 19 wells in 2008 Actively pursuing project for increased gas sales Tunisia Algeria Libya MBOEPD 3 ~4 MM gross acres in 5 concessions (20% - 50% interest1) 80% 1) Assumes ETAP backs in for 50% of PXD working interest '06 4 5 '07 '08 Q1 Q2 90+% 2007 Q3 5

South Africa Net production currently 3 - 4 MBOEPD Includes Sable oil and initial gas & condensate from South Coast Gas project Net production expected to increase in late 2008 / 2009 Sable oil field life extended due to higher oil prices and better well performance Only initial South Coast Gas wells currently on production; expect large ramp up in late 2008 as reinjected Sable gas comes online 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

Oooguruk Project On Schedule Production facilities complete and export pipeline installed Rig installed; drilling underway Expect to drill 15 wells in 2008 Initial activity focused on drilling a disposal well, 2 Kup C production wells and 1 injector First oil production expected 1H 2008 with first sales mid-year Peak gross production of 15 - 20 MBOPD in 2010 Gross reserve potential of 70 - 90 MMBO Expansion opportunities Expansion opportunities 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 70% WI (Operator) Prudhoe Bay Kuparuk River Alpine TAPS

Investment Highlights On track to deliver 12+% production per share CAGR through 2011 Core onshore assets driving growth (Spraberry, Raton, Edwards and Tunisia) Oooguruk project on schedule for first sales in mid-2008 Expecting 20+% cash flow CAGR through 2011 Includes benefit from legacy hedge expiration and reduced VPP obligation Oil-related projects significant contributor Significant free cash flow through 2011 2008 capital budget in line with cash flow Low-risk drilling inventory with over 6,500 locations Continuing to expand core areas with attractive bolt-on acquisitions Proved reserves of 874 MMBOE1; reserve to production ratio of 25 years Forecasting 2007 all-in F&D of $14 to $17 / BOE with similar results expected for 2008 Pioneer Southwest Energy Partners L.P. (PSE) IPO planned for Q1 '08 Pro forma Canadian divestiture as of 12/31/06

Delivering Consistent Production Growth 2006 Q1 2007 Q2 2007 Q3 2007 Q4 2007 East 90 89 96 101 103 2 90 101 - 106 892 1) Pro forma for the divestiture of Canada 2) Q1 '07 production impacted by weather-related losses in Raton, Mid-Continent and Spraberry totaling ~3 MBOEPD 3) Reflects actual 9 months average weighted shares outstanding (122.5 MM shares) and assumes no additional share repurchases in Q4 (end of Q3 shares outstanding were 119.7 MM) 2006 Q2 '07 MBOEPD1 Q1 '07 Q3 '07 96 101 Q4 '07 On track to deliver 12+% production per share growth in 2007 Average Shares Outstanding (MM) 127.6 121.83

2007 Finding & Development Cost Estimate Reserve adds from successful drilling in core onshore areas (Spraberry, Raton, Edwards and Tunisia) and recent acquisitions in Raton, Spraberry and Barnett Shale All-in finding and development cost expected to range from $14 to $17 / BOE Organic F&D expected to range from $17 to $20 / BOE $11 to $15 / BOE excluding Spraberry and Raton PUD drilling Reserve replacement expected to be >300% Similar F&D results expected for 2008

Oil-Related Projects Drive Revenue Growth 2007 2008 2011 Base 36 91.925 33 Oil Growth 0 10.144 9 Gas Growth 0 7.52 12 Oil Gas East 65 35 2007 2011 Oil 65% Gas 35% Spraberry Oooguruk Tunisia South Coast Gas3 Raton Edwards Barnett Shale Production MMBOE1 Gas Oil Incremental Revenue2 Pro forma for Canadian divestiture, PXD total production is ~45% liquids / 55% gas Reflects December strip pricing South Coast Gas prices indexed to Brent crude

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 Delivering 12+% Production Per Share Growth1 Development Spraberry Raton Edwards Tunisia South Coast Gas Oooguruk Barnett Shale Mississippi Resource Play Upside Edwards Tunisia Rockies Barnett Shale Mississippi MMBOE 33 31 1) Production pro forma for Deepwater GOM, Argentina and Canada divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 12+% Per Share CAGR Per Share: 18% Per Share: 12+% 35 - 36

2008 2009 2010 2011 Historical Production VPP Oil 7.9 7.6 6.8 3.7 VPP Gas 5 4.5 Legacy Hedges 10 Legacy Hedge Terminations Contribute Significant Cash Flow Improvement VPP Oil Obligation 12 Includes 6 MBOPD of unwound hedges where losses locked in and 4 MBOPD hedged at $32 / BBL Cash flow improvements reflect December strip pricing 23 7 4 Legacy Hedges1 (100% oil)1 Cumulative Pre-Tax Cash Flow Increase vs.2008 ($MM)2 - 200 300 400 MBOEPD 5 10 VPP Gas Obligation 8 5 7

2006 2007 2008 2009 2010 2011 East 0.756 0.85 1 1.3 1.55 1.8 Delivering 20% Cash Flow Growth Cash flow from operations reflects the divestiture of Canada in late 2007, December strip pricing and expected growth from development drilling and development projects Cash Flow1 ($ billions) 0.8 - 0.9 2011 2006 1.7 - 2.0 Cash flow growth driven by production growth (2/3) and legacy oil hedge expiration (1/3) Expect to be free cash flow neutral in 2008 and positive thereafter ROCE expected to improve to 14% - 16% by 2011 primarily due to expiration of legacy hedges and declining VPPs ~20% CAGR 2007 0.75 1.0 - 1.1 2008 1.2 - 1.4 2009 1.5 - 1.7 2010

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) 199,112 9,897 2,500 NYMEX Price ($/MMBTU)1 $ 8.42 $ 9.00 $ 8.07 % Hedged N American Gas2 55% 3% 1% Crude Swaps - Old (BPD) 4,000 - - NYMEX Price ($/BBL) $32.00 - - Swaps - New (BPD) 11,250 8,000 4,000 NYMEX Price ($/BBL) $ 71.79 $ 71.57 $ 71.46 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) 500 500 500 Blended Index Price ($/BBL)3 $ 44.33 $ 41.75 $ 39.63 % Hedge Total Liquids2 38% 20% 7% Total Equivalent % Hedged Total Equiv.2 46% 10% 3% Hedge Position as of 1/14/2008 HEDGING STRATEGY Capture Spikes Protect Capital Budget and Project Economics

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