Exhibit 99.1

Investor Meetings May 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 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 the Rockies, Tunisia and other onshore Gulf Coast areas 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 GOM 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 drilling program from 190 to >300 wells Currently operating 12 rigs; increasing to 14 rigs by mid-year and 18 rigs by year end Strong IRRs ~20% @ $45 oil ~40% @ January strip ($66 oil) Majority of wells in 2006 will test deeper Wolfcamp potential Pursue acreage expansion program and bolt-on acquisitions Recently commenced 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 - 100% Drilling Success YTD Increased land position to ~200,000 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 (310 BCF); development plan being prepared Wells tested initially at 2.5 - 3.2 MMCFPD unstimulated; on production in late Q2 Second new field discovery at Stingray On production in late Q2 Drill next 3 new field prospects in Q2 4 rigs working along trend 2 rigs to be added over remainder of 2006 1 additional rig contracted for 2007 Increasing 2006 drilling program to 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 94 wells drilled through April ~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 to be completed by July Targeting 30 wells on production by end Q3 Includes wells awaiting completion and pilot wells 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; drilling on existing 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 Plan to complete 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 to commence in Q2 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 to be 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 expected to be online during May 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 to be put on production from 2005 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 8 horizontal wells (3 pilots) planned for 2006 Spudding 2 wells in Q2 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 10% WI? option to 50% 25,000 acres in Cook Inlet TAPS Central North Slope Satellites Cronus - PXD 90% WI (Op) Identified thick oil column; evaluating further appraisal 51,000 acres Alpine 500 MMBO Planning 2006 / 2007 Winter Drilling Program

Q1 Progress Secured permits and sanctioned project 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 GOM divestiture Gross reserve potential: Main amplitude: 25 - 50 MMBOE Upside amplitudes could expand reserves to 90 MMBOE PXD Operator, 55% WI 2006 drilling plan Appraisal on Clipper amplitude and 2 additional exploration tests commencing 3Q Rig contracted in early 2005 at half current market rate Strong IRRs ~45% @ $45 oil ~80% @ January strip ($66 oil) Possible development scenarios: Standalone facility Subsea tie-back options to 3rd party host (depicted in diagram on right) Clipper Marco Polo Front Runner Allegheny Genesis GC 299 22 mi. 16 mi. 8 mi. 20 mi. Clipper Discovery GC 300 First Production: 2009

Tunisia Provides Core Area Potential Adam Concession 100% drilling success to-date 9 for 9, including Adam 4 in Q1 Currently acquiring 3-D seismic; extends into Jenein Nord Two-rig drilling program underway Gas contract approval expected Q2 Agreement retroactive for gas delivered in 2005 (3.5 MMCFPD gross) Currently delivering 8 MMCFPD @ ~$5.50 per MCF Jenein Nord Acquired Anadarko's remaining equity interest in February 2006 PXD to operate at 100% WI* Rig planned for late 2006 to drill 3 wells Borj El Khadra On trend with Adam and Jenein Nord Drilling 1 well in Q2 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 F-A Pipeline to Shore Sable 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 7-well subsea tie-back to existing F-A platform Subsea infrastructure and well tie-ins during 1H 2007 First production 2H 2007 Average 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 to follow 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) Plan to test 3 plays during 2007 Nigeria OPL 256 PXD 25% WI Recently drilled Pina well non- commercial gas discovery 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 currently 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

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: May 2006 strip prices are approximately 3% higher than January strip prices on average over 2006-2012 period.

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

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

70% development projects 20% lower-risk resource plays 10% high-impact exploration Capital Allocation and Returns Spraberry Raton Pawnee Horseshoe Canyon Oooguruk S. Coast Gas Clipper Edwards Trend Uinta / Piceance Tunisia W. Africa Alaska Miss. Development Drilling Development Projects Resource Plays High-Impact Exploration Projected A-Tax Estimated Share Repurchase DROI2 1 (Full Project Life) 1 Based on strip pricing 2 Based on development NAV (10%) of $54 per share assuming a $40 - $45 share price

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 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 North American Operated Growth Areas Requiring Additional Rigs YE 2005 Q1 Q2 Q3 Q4 YE 2006 YE 2007 Spraberry Contracted 10 - 4 1 - 15 15 Negotiating - - 3 1 - 4 4 Rigs Required 10 19 19 Edwards Contracted 2 1 1 1 1 6 7 Rigs Required 2 6 7 No. LA & MS Contracted - - - 2 - 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 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

Pro Forma Capital Structure as of March 31 Deepwater Gulf of Mexico divestiture closed in March; Argentina divestiture closed in April Divestiture proceeds will be 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

Pro Forma Senior Notes and Credit Facility Maturities as of 3/31/06 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 $100 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 A Successfully tendered for all but $54 MM of $350 MM of 6 1/2% Senior Notes due January 2008 $54 MM A 6 1/2%

Remaining Hedge Positions as of 5/8/06 1) % of production Gas Apr-Dec 2006 2007 2008 Swaps (MMBTUD) 73,885 24,195 - Hedge Price ($/MMBTU) $4.31 $4.00 - Collars (MMBTUD) 108,345 215,000 - Call Price ($/MMBTU) $14.27 $11.85 - Put Price ($/MMBTU) $6.55 $6.57 - % Hedged N American Gas1 54% 65% - % Hedged N American Gas (Swaps only) 1 22% 7% - Crude Swaps (BPD) 5,327 10,000 10,000 Hedge Price ($/BBL) $39.33 $30.96 $30.62 Collars (BPD) 6,665 2,000 - Call Price ($/BBL) $67.12 $89.50 - Put Price ($/BBL) $42.12 $50.00 - % Hedge Total Liquids1 32% 30% 20% % Hedged Total Liquids (Swaps only) 1 14% 25% 20% Total Equivalent % Hedged Total Equiv. 1 45% 49% 8% % Hedged Total Equiv. (Swaps only) 1 19% 13% 8%

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 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.