Exhibit 99.1
| Independent Petroleum Association of America London Oil & Gas Investment Symposium July 12, 2006 |
| Forward-Looking Statements Except for historical information contained herein, the statements in this presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward- looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of oil and gas prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, third party approvals, international operations and associated international political and economic instability, litigation, the costs and results of drilling and operations, availability of drilling equipment, Pioneer's ability to replace reserves, implement its business plans (including its plan to repurchase stock), or complete its development projects as scheduled, access to and cost of capital, uncertainties about estimates of reserves, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. Please see the Appendix to this presentation for other important information. |
| Strategy For Strong, Consistent Growth Focus on predictable oil and gas basins in North America that can deliver strong, consistent growth Represents 98% of reserve base Expanding development drilling Lowering risk profile by expanding unconventional resource plays and reducing exploration capital Building significant acreage positions in existing and new plays at attractive entry cost Adding to core area positions with low-risk, bolt-on acquisitions in plays with extensive operating experience A Smaller, Focused Company with a Stronger Platform for Growth |
| Pioneer Today (Post Divestitures) T unis Cape T own Operating Areas Tunisia Nigeria Equatorial Guinea South Africa Sable / South Coast Gas Company Metrics Post Divestitures1 Company Metrics Post Divestitures1 Total Reserves1 865 MMBOE Pre-Tax PV10 $8.6 B % PDP 61% % Gas 55% R / P Ratio ~25 Years % North America 98% % Operated Production ~90% 1) Pioneer pro forma as of 12/31/05 for Argentina and Deepwater Gulf of Mexico divestitures Dallas Denver Calgary Chinchaga Horseshoe Canyon Raton Hugoton Pawnee / Edwards West Panhandle Uinta & Piceance Spraberry Anchorage Alaska Cook Inlet North Slope No. LA and MS |
| Significant Unbooked Resource Potential Year-end '05 Reserves1 (MMBOE) Resource Potential2 (MMBOE) Spraberry 404 100 Raton 246 70 Canada 24 60 Development Projects3 11 80 Pawnee & Edwards Trend 22 170 Uinta/Piceance 14 130 Tunisia 4 40 Mid-Continent 136 - Other 4 - Total 865 ~650 3 Development projects include South Coast Gas, Oooguruk and Clipper 1 Pro forma for Argentina and Deepwater Gulf of Mexico divestitures 2 Excludes high-impact exploration F&D cost for ~650 MMBOE projected at $10 - $15 / BOE, reflecting capital costs of ~$6 Billion4 Multi-year drilling inventory of over 6,000 locations 4 Compares to 3-year and 5-year F&D costs of $10.62 / BOE and $9.55 / BOE, respectively |
| 2006 Capital Budget Generates Strong IRRs & Growth Development Resource Plays High-Impact East 924 247 137 20% 17% 53% High-Impact Exploration Alaska • West Africa • Norphlet • Clipper Amplitudes ~30% - 80% risked pre-tax IRRs @ strip Resource Plays Edwards • U - P • Sand Wash • No. LA • Tunisia Silurian • Mannville ~40% - 100+% risked pre-tax IRRs @ strip Development Projects Oooguruk • SC Gas • Clipper ~35% - 80% risked pre-tax IRRs @ strip Development Drilling Spraberry • Hugoton • West Panhandle • Pawnee • Raton • Chinchaga • HSC ~40% - 100+% pre-tax IRRs @ strip Total Capital: $1.3 B 10% |
| Targeting Double-Digit Production Growth Production Targets 2006 - 2010 CAGR Development 10% W/ Risked Resource Plays up to 18% W/ Risked High-Impact Exploration up to 21% Company Target >10% MMBOE Edwards, Uinta-Piceance & Tunisia Growth driven by Spraberry, Raton, Canada, South Coast Gas, Oooguruk & Clipper Alaska & Norphlet |
| Expect to meet or exceed 95 - 100 MBOEPD 2006 exit rate North American production up 7% versus Q1 2005 Production from Spraberry, Raton and Canada continuing to increase Continuing to ramp up rig count All necessary rigs under contract Two new Edwards fields adding to future production profile Additional upside from resource plays in other onshore Gulf Coast areas, Rockies and Tunisia Oooguruk and South Coast Gas development projects on schedule 2Q05 3Q05 4Q05 US 76 68.53076676 77.64118783 80.97299659 80.9372252 86 Canada 6.27328537 6.939150037 6.972016268 6.942510163 6 8 Africa 10 10.45098396 9 8 8 6 MBOEPD 92 95 95 - 100 U.S. Canada Africa 1 Pro forma for Argentina and Deepwater Gulf of Mexico divestitures; assumes 2005 and 2006 VPP volumes in place for all of 2005 (i.e. volumes effective 2/1/05 plus 9 MBOED effective 1/1/06) On Track to Deliver Production Growth Targets 1 2005 Avg. Prod. Q1 2006 2006 Exit Rate Confident that double-digit compound annual production growth will be delivered over next 5 years |
| Spraberry Anchors Growth Glasscock Reagan Upton Midland Martin Spraberry Trend Pioneer Acreage Pioneer's largest asset 315,000 gross acres 4,200 active wells Over 95% operated 2006 Plan Ramping up Permian drilling program from 190 to 338 wells Currently operating 15 rigs; increasing to 20 rigs by year end Strong IRRs ~20% @ $45 oil ~40% @ January strip ($66 oil) Majority of wells in 2006 will test deeper Wolfcamp potential Expected to increase reserves and production Pursue acreage expansion program and bolt-on acquisitions Recently commenced up to a 200-well JV with major oil company Expect to average 9% / year production growth through '09 Q1 '06 production up 16% from Q1 '05 |
| Edwards Trend - Low Risk Exploration Increased land position to ~222,000 gross acres Strong IRRs ~50% @ $6.50 gas ~60% @ January strip ($9 gas) 4 successful wells in Sinor area First new field discovery similar to Pawnee On production late Q2 / Q3 Development plan for field being prepared Second new field discovery at Stingray On production Q3 3 new field prospects being drilled and tested 4 rigs working along trend 2 rigs to be added over remainder of 2006 At least 1 additional rig expected for 2007 2006 drilling program: 35 - 40 wells ~1/3 targeting new fields Existing Gas Fields PXD Fields PXD Focus Area New PXD Trend Wells LaSalle Fayette Pawnee 310 BCF Washburn SW Kenedy Mertz / NE Word Sinor Discoveries (4 wells) Stingray Gross Resource Potential: 1-3 TCF |
| Raton Expansion Continues New Mexico Colorado Raton Basin 310,000 gross acres Drilling program increased from 289 wells in 2005 to 330 wells in 2006 2006 program on track Over 150 wells drilled through June ~1,650 drilling locations remain Strong IRRs ~35% @ $6.50 gas ~40% @ January strip ($9 gas) 2006 Objective: Focus on more efficiently recovering the resource Lower field pressure through wellhead / booster compression and additional pipelines Continue to refine reservoir characterization model to high-grade future drilling locations Continue to actively manage costs via the integrated well service model Raton Vermejo Production expected to meet or exceed 5% - 7% annual growth target versus 2005 Q1 '06 production up 6% from Q1 '05 |
| Rockies Emerging Resource Plays Castlegate CBM (Uinta Basin) Plan to drill one horizontal pilot and one high-density pilot to evaluate production options Evaluate horizontal and vertical well results for project sanction by year end Columbine Springs CBM (Piceance Basin) 7-well extension pilot completed Targeting 33 wells on production by end Q3 Next step will be evaluating well performance Key to success will be implementation of effective water handling capability Evaluate sanction of full field development by year end Main Canyon Entrada Gas Play 3 wells planned for Q3; shooting additional 3-D seismic Sand Wash Basin Lay Creek CBM pilots (see next slide) Piceance Basin Uinta Basin Castlegate Columbine Springs Colorado Utah Lay Creek Sand Wash Basin Entrada |
| Reworked wells in prior operator's two pilots Determined coals are permeable and can be put on production without excessive water production Started construction of central water processing facility, including two disposal wells Expect to complete 14 wells during 2H 2006 and infrastructure to commence gas sales by year end Drilled new 5-well pilot towards southern end of acreage Coals thicker than expected and continuous throughout acreage position Confirmed gas content Two additional CBM pilots during Q3 Streamlining permitting by focusing activity on fee surface and minerals outside of BLM lands Forming federal units for efficient development Evaluate pilot results for full field development in late 2006 Lay Creek Pilots Encouraging High pressure pipeline 2 additional pilots being drilled Workovers in 2 existing pilots 5-well pilot drilled Washakie Basin Sand Wash Basin WY CO Atlantic Rim Play >1 TCF gross resource potential |
| Canada Production Growing Chinchaga 44 development wells drilled in Q1 2006 90% success rate All wells on line Horseshoe Canyon CBM 70,000 gross acres with ~500 locations Drilling program increased from 157 wells in 2005 to 200 wells in 2006 100 wells from 2005 to be put on production 18 wells drilled in Q1 Two rigs contracted to drill remaining 182 locations Strong IRRs ~70% @ $6.50 gas ~100+% @ January Strip ($9 gas) Net resource potential: >200 BCF Mannville CBM ~75,000 gross acres 3 pilots (2 wells each) planned for 2006 1st pilot drilled and dewatering Last 2 pilots to be drilled in Q3 Identifying drilling and completion techniques that allow commercial production rates Net resource potential: 250 BCF Calgary Edmonton Horseshoe Canyon Mannville Chinchaga Q1 2006 production up 5% from Q1 2005 |
| BEAUFORT SEA National Petroleum Reserve Alaska (NPRA) Significant Growth Opportunities in Alaska Storms Area Exploration PXD 50% WI (Op) 153,000 acres NPRA Exploration PXD 20% - 30% WI 1.4 million acres Total Pioneer 1.7 million acres Oooguruk Discovery PXD 70% WI (Op) 58,000 acres Prudhoe Bay 13 BBO Kuparuk River 2.5 BBO Anchorage Beaufort Sea Cosmopolitan Discovery PXD 50% WI (Op) 25,000 acres in Cook Inlet TAPS Alpine 500 MMBO Planning 2006 / 2007 Winter Drilling Program |
| 2006 YTD progress Secured permits and sanctioned project (February) Completed gravel drill site construction (April) Remainder of 2006 Contour and "armor" gravel drill site Procure equipment and services Fabricate modules to be used on drill site Modify drilling rig for 2007 installation First Production: 2008 Oooguruk Development Underway |
| Clipper Provides Significant Reserve Upside Discovery well: June 2005 Excluded from Deepwater Gulf of Mexico divestiture Gross reserve potential: Main amplitude: 25 - 50 MMBOE Upside amplitudes could expand reserves to 90 MMBOE PXD Operator, 55% WI 2006 drilling plan Commenced drilling 2 appraisal wells and 1 exploration test late June Rig contracted in early 2005 at half current market rate Strong IRRs ~45% @ $45 oil ~80% @ January strip ($66 oil) Possible development scenarios: Subsea tie-back options to 3rd party host (depicted in diagram on right) Standalone facility Clipper Front Runner Genesis GC 299 22 mi. 16 mi. Clipper Discovery GC 300 First Production: 2009 |
| Tunisia Provides Core Area Potential Adam Concession 100% drilling success to-date (9 for 9) Includes Adam 4 in Q1; initial production 1800 BOPD; production expected to reach 2500 - 3000 BOPD during Q3 ADAM 5 spud in late Q2 Acquired 752 km2 of 3-D seismic Gas contract receiving final government approval Agreement retroactive for gas delivered in 2005 (3.5 MMCFPD gross) Currently delivering 7 MMCFPD @ ~$5.50 per MCF Jenein Nord Acquired Anadarko's remaining equity interest in Q1 PXD to operate at 100% WI* Acquired 400 km2 3-D seismic Rig planned for Q4; plan to drill 2 wells by year end Borj El Khadra On trend with Adam and Jenein Nord Drilling 1 well in Q4 Tunisia Algeria Libya El Hamra (Op) PXD 100% WI 1.3 MM gross acres Anaguid PXD 45% WI 1.2 MM gross acres Jenein Nord (Op) PXD 100% WI 0.3 MM gross acres Adam Concession PXD 20% WI 0.2 MM gross acres Borj El Khadra PXD 40% WI 1 MM gross acres * Subject to ETAP participation up to 50% WI |
| South Coast Gas Project Progressing Mossel Bay Synfuels Plant Existing F-A Pipeline to Shore Sable Existing F-A Platform ATLANTIC OCEAN Cape Town Mossel Bay Block 9 Cluster A Cluster B Cluster E Cluster D Cluster C Initial development Potential expansion (post 2012) Block 9 PXD 45% WI; PetroSA 55% WI (Operator) Project Capital: $462 MM ($208 MM net) Development drilling underway; to be completed by early 2007 Three wells drilled; awaiting completion 7-well subsea tie-back to existing F-A platform Subsea infrastructure and well tie-ins during 1H 2007 First production 2H 2007 Average gross production of ~100 MMCFPD through 2012 Strong IRRs ~25% @ $45 oil ~40% @ January strip ($66 oil) Gross reserves of 203 BCF (gas) and 5.5 MMB (condensate) 11 MMBOE booked to-date by PXD Subsequent development phases anticipated post 2012 Gross resource potential >200 BCF |
| Significant Growth Opportunities in West Africa Nigeria Malabo Lagos Port Harcourt Wari 320 Equatorial Guinea 256 H PXD Interests >250 MMBOE Discoveries Shell "Big Cat" Discoveries (July 2005) 3 plays scheduled for 2007 drilling Nigeria OPL 256 PXD 25% WI Well planned Q2 2007 Shell discovery in adjacent OPL 245 (1 km NE of permit boundary) OPL 320 PXD 30% net WI; technical operator Well planned Q4 2007 3-D seismic being processed Shell discovery in adjacent OPL 322 (12 km south of permit boundary) Equatorial Guinea Block H PXD 50% WI Well planned Q3 2007 Devon discovery in adjacent Block P (27 km SE of permit boundary) Devon Discovery (Sept. 2005) |
| Corporate Goals (2006 - 2010) Top quartile stock return Top quartile production and reserves per share growth Deliver double-digit compound annual production growth from development activities Additional production upside from: Moving lower-risk resource plays from appraisal to full-scale development Acquiring bolt-on assets High-impact exploration Maintain strong balance sheet Debt-to-book below 35% Continue to reduce share count |
| Appendix |
| Key Pricing Assumption Strip pricing in all presentations refers to January 2006 prices: Crude ($ / BBL) Gas ($ / MCF) 2006 67.66 9.31 2007 69.01 10.09 2008 67.29 9.66 2009 65.70 9.14 2010 64.75 8.54 2011 64.50 8.30 2012+ 63.30 8.30 Note: July 2006 strip prices are approximately 2% lower than January strip prices on average over 2006-2012 period. |
| NAV Update NAV 2P 58 Transition 2 Resource Plays 11 Transition 2 Traditional Exploration 3.5 Transition 3 Development NAV range is risked and discounted at 8% - 10% due to long-life nature of the assets Resource Play exposure is substantial, even on a risked basis Risked High-Impact Exploration represents only a small portion of capital, but a large potential future upside $54-$64 Development Resource Plays High-Impact Exploration $10-$16 $4-$9 Significant Unbooked Potential 865 MMBOE - proved ~300 MMBOE - low-risk resource potential ~350 MMBOE - potential resource upside |
| 2006 Capital Allocation, Returns & Potential Reserve Additions Spraberry Raton Pawnee Horseshoe Canyon Oooguruk S. Coast Gas Clipper Edwards Trend Uinta / Piceance Tunisia W. Africa Alaska Miss. Development Drilling (45-50 MMBOE) Development Projects (8-12 MMBOE) Resource Plays (15-20 MMBOE) High-Impact Exploration (Reserves contingent on success) Projected A-Tax Estimated Share Repurchase DROI2 1 (Full Project Life) 1 Based on strip pricing. Discounted Return on Investment (DROI) is defined as present value of future cash flow discounted at 10% divided by discounted capital investment 2 Based on development NAV (10%) of $54 per share assuming a $40 - $45 share price 70% Development 20% Resource Plays 10% High-Impact Exploration 1.3 B Capital Budget |
| Summary of Portfolio Investment $45/Bbl & $6.50/Mcf1 $45/Bbl & $6.50/Mcf1 $45/Bbl & $6.50/Mcf1 $45/Bbl & $6.50/Mcf1 Strip Pricing1 Strip Pricing1 Strip Pricing1 Strip Pricing1 Investment Before Tax Before Tax After Tax After Tax Before Tax Before Tax After Tax After Tax Investment IRR DROI IRR DROI IRR DROI IRR DROI Development Spraberry 19% 1.4 14% 1.2 40% 2.2 31% 1.6 Raton 33% 2.4 25% 1.5 40% 2.8 35% 1.8 Pawnee 85% 2.2 65% 2.0 100+% 2.6 95% 2.4 Horseshoe Canyon 71% 3.0 55% 2.3 100+% 3.5 85% 2.6 South Coast Gas 24% 1.4 20% 1.2 38% 1.8 31% 1.5 Oooguruk 21% 1.5 16% 1.2 37% 2.4 28% 1.8 Clipper 44% 1.8 29% 1.4 82% 2.9 60% 2.1 Resource Plays Edwards Trend 50% 1.9 35% 1.7 60% 2.4 45% 2.0 Uinta/Piceance 30% 2.3 25% 1.5 40% 2.6 35% 2.0 Tunisia 100+% 5.2 100+% 2.8 100+% 7.0 100+% 3.5 High-Impact Exploration West Africa 23% 1.8 20% 1.4 31% 2.7 23% 1.6 Alaska 28% 1.8 23% 1.5 40% 2.5 28% 1.8 1 Assumes capital expenditures commensurate with current strip pricing environment |
| Continuing to Accelerate Low-Risk Drilling* 2004 2005 2006 110 1,060 *2004 well count pro forma for merger with Evergreen Resources; all years exclude Argentina and Deepwater Gulf of Mexico 950 Development Drilling / Projects (Expect ~100% success rate) New Resource Plays (Expect ~40% - 60% success rate) 150 110 780 480 |
| Rigs Secured To Execute Plan Rigs Added By Quarter U.S. Operated Growth Areas Requiring Additional Rigs YE 2005 Q1 Q2 Q3 Q4 YE 2006 YE 2007 Permian Contracted 12 - 3 5 - 20 20 Negotiating - - - - - - - Rigs Required 12 20 20 Edwards Contracted 2 1 1 1 1 6 7 Rigs Required 2 6 7 No. LA & MS Contracted - - 1 1 - 2 2 Negotiating - - - - - - 2 Rigs Required - 2 4 U - P & Sand Wash Contracted - 1 1 - - 2 2 Owned - 1 - - - 1 1 Rigs Required - 3 3 Alaska Contracted 1 - - - - 1 2 Rigs Required 1 1 2 |
| Capital Cost Creep % Increase % Increase Item 2005 2006E Drilling Day Rate 40% 20% Fracs 70% 10% Cement 20% 20% Logging 100% 5% Casing 40% 10% Mud 50% 10% Pumping Units 100% 5% Commodity Increase 35% 0% Representative Industry Cost Recent leveling in commodity prices may lead to a tempering of capital cost increases in 2006 as compared to 2005 Day Work Rate ($ / FT Drilled) WTI Price ($ / barrel) WTI vs. Drilling Capital Correlation (Spraberry Example) |
| Q1 Q2 Q3 Q1 2000 Q2 2000 Q3 2000 Q4 2000 Q1 01 Q2 2001 Q3 01 Q4 01 Q1 02 Q2 02 Q3 02 Q4 02 Q1 03 Q2 03 Q3 03 Q4 03 Q1 04 Q2 04 Q3 04 Q4 04 Q1 05 Q2 05 Q3 05 Q4 05 Q1 06 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 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 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 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 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 Q1 2006 Production Costs (per BOE) Production & Ad Valorem Taxes Q 1 2005 Q 2 2005 $8.53 $9.30 $2.23 $0.88 $4.80 $ .62 Q 3 2005 $2.54 $1.19 $5.00 $ .57 $9.89 Q 4 2005 $9.73 $2.72 $1.00 $5.63 $ .54 $3.32 $ 1.04 $4.81 $ .56 $11.04 $2.96 $1.21 $ .72 Q 1 2006 $6.15 Note: All periods presented have been restated to exclude discontinued operations. VPP-Adjusted Production Cost $9.47 $9.06 $9.19 $8.62 $8.19 Workovers LOE Transportation |
| Q1 2006 Production Cost vs. Peers PXD NBL EOG RRC NFX KMG CHK DVN APA APC XTO XEC KWK PPP PXP Production Cost 9.47 6.72 7.43 7.55 7.56 7.64 7.67 8.47 8.66 9.88 10.41 11.03 11.04 12.34 13.03 VPP 1.58 $ / BOE 11.04 6.72 7.43 7.55 7.56 7.64 7.67 8.47 8.66 9.88 13.03 12.34 11.04 11.03 10.41 Q1 2006 Average (9.36) 9.47 if VPP Volumes Added Sources: UBS Investment Research 1.57 |
| Senior Notes & Credit Facility Maturity Schedule B Convertible notes assumed from EVG; if not converted prior to 12/06, Pioneer will redeem for cash at par 2006 2007 2008 2009 2010 2011 2012 2028 $32 MM 8 1/4% $6 MM 5 7/8% $250 MM 7 1/5% 2016 $527 MM 5 7/8% 2021 $98 MM 4 3/4% B 2018 $450 MM 6 7/8% $ - 5-Year, $1.5 B Credit Facility Debt Objectives: Maintain debt-to-book capitalization ratio at less than 35% Maintain long-term debt to EBITDAX ratio at less than 2x $4 MM 6 1/2% A A Net of cash on hand |
| Remaining Hedge Positions as of 6/30/06 1) % of production Gas Jul-Dec 2006 2007 2008 Swaps (MMBTUD) 73,932 59,195 - Hedge Price ($/MMBTU) $4.31 $7.06 - Collars (MMBTUD) 90,000 30,000 - Call Price ($/MMBTU) $14.38 $11.02 - Put Price ($/MMBTU) $6.56 $6.50 - % Hedged N American Gas1 47% 24% - % Hedged N American Gas (Swaps only) 1 21% 16% - Crude Swaps (BPD) 5,000 10,000 10,000 Hedge Price ($/BBL) $37.20 $30.96 $30.62 Collars (BPD) 6,500 2,000 - Call Price ($/BBL) $66.41 $89.50 - Put Price ($/BBL) $41.92 $50.00 - % Hedge Total Liquids1 31% 31% 20% % Hedged Total Liquids (Swaps only) 1 13% 26% 20% Total Equivalent % Hedged Total Equiv. 1 41% 26% 8% % Hedged Total Equiv. (Swaps only) 1 18% 19% 8% |
| Pro Forma Capital Structure as of March 31 Deepwater Gulf of Mexico and Argentina divestitures closed in March and April, respectively Divestiture proceeds being used to: Fund a portion of the Company's 2006 & 2007 capital budgets Initiate the remaining $359 MM share repurchase program Retire short-term debt Strong balance sheet and financial flexibility to execute forward plan ($ Billions) 12/31/05 03/31/06 Total assets 7.3 6.3 Long-term debt (net of cash) 2.1 0.5 Other current and noncurrent liabilities 3.0 2.9 Stockholders' equity 2.2 2.9 |
| Successful Argentina Divestiture Divestment rationale Low margins Government-controlled pricing Declining production Downward reserve revisions Sale price: $675 MM Proved reserves: 101 MMBOE ~65% gas / 35 % liquids 2005 production: ~32.5 MBOED Received high end of proved NAV range After-tax SEC PV10 of ~$630 MM assuming current oil export tax continues beyond legislated expiration date of February 2007 |
| Successful Deepwater GOM Divestiture Divestment rationale Escalating rig costs Opportunity to reduce exploration risk and production volatility Attractive market valuations for GOM assets Sale price: $1.3 billion New "high water" mark for GOM sales ($65 / proved BOE) Excludes Clipper discovery valued at ~$150 MM - $500 MM (25 - 90 MMBOE gross resource potential) Proved reserves: 20 MMBOE ~65% gas / 35% liquids Production at time of sale: ~40 MBOED Received high end of NAV range After-tax SEC PV10 of $589 MM |
| 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," "potential," "upside" 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 strictly by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. |
| Net Asset Value Disclosure Pioneer does not consider "Net Asset Value" and "Net Asset Value Per Share" to be "non-GAAP financial measures," as defined in SEC rules. Pioneer uses Net Asset Value as an estimate of fair value. Net Asset Value and Net Asset Value Per Share should not be considered as alternatives to Standardized Measure, Stockholders Equity or per share statements of those measures. Pioneer's NAV calculation is based on numerous assumptions that may change as a result of future activities or circumstances. NAV is calculated using strip commodity prices as of January 2006 and is discounted at 10%, unless otherwise indicated. In the context of determining Pioneer's Net Asset Value Per Share, Pioneer adds other tangible assets adjusted for working capital and deducts long-term debt and other liabilities, including future income taxes and the impact of existing hedge positions. |