Investor Presentation April 2014

Transcription

1 Investor Presentation April 2014

2 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 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 mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities 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, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company s industrial sand mining and oilfield services businesses 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. 2

3 Pioneer At A Glance Total Enterprise Value ($B) ~$ Drilling Capex ($B) $ Production (MBOEPD) Reserves (BBOE) Reserves + Resource (BBOE) > Top U.S. Fields By Rig Count 1 (Pioneer Operated Count in Green 43 rigs) Resource-focused strategy, with activity concentrated in 3 of the most active U.S. fields Best performing energy stock in S&P 500 since Operating in core Spraberry/Wolfcamp asset since early 1980s PXD holds ~825,000 acres in Spraberry/Wolfcamp Largest producer in Spraberry/Wolfcamp with 35 rigs operating (24 horizontal and 11 vertical) and 7,000+ producing wells Preeminent, low-cost operator benefitting from vertical integration strategy Attractive derivative positions protect margins ~80% of Spraberry/Wolfcamp oil production protected against Midland-Cushing differential blowout Strong investment grade financial position 1) Baker Hughes Rig Count (2/14/14) and PXD Internal Spraberry/Wolfcamp Gross Production By Operator (MBOEPD) ) November 2013 IHS data, gross reported oil and wet gas

4 Share Price Performance of Permian Basin Operators since ,200% Since 2009, the combined enterprise value for Permian-weighted companies listed has increased from $20 billion to $55 billion 1,000% 800% 600% 400% 200% - Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 PXD CXO LPI FANG XEC AREX EGN ATHL RSPP S&P 500 1) LPI, FANG and RSPP s price performance based on IPO price since respective IPO occurred after 1/1/2009 4

5 2014E Capital Spending and Cash Flow 1 NYMEX Gas Price ($/MCF) Drilling Capital: $3.0 B $2,165 MM northern Spraberry/Wolfcamp area o $1,225 MM for horizontal drilling program o $440 MM for vertical drilling program o $400 MM for infrastructure, land and science o $100 MM for gas processing facilities $205 MM southern Wolfcamp joint venture area (net of carry) o $140 MM for horizontal drilling program o $65 MM for vertical drilling, infrastructure, land and science $545 MM Eagle Ford Shale o $480 MM for horizontal drilling program o $65 MM for infrastructure and land $100 MM Other Assets Other Capital (vertical integration, buildings and field offices): $285 MM Capital program funded from: Operating cash flow of ~$2.4 B Cash on hand (~$0.4 B at the end of Q4) Proceeds from divestitures Capital program of $3.3 B Sensitivity to Commodity Prices ($ MM) NYMEX Oil Price ($/BBL) 2014E Average Price $95/BBL oil and $4.50/MCF gas 1) Capital spending includes land capital and excludes asset retirement obligations, capitalized interest and G&G G&A; also excludes drilling capital incurred for Alaska and Barnett Shale prior to their divestiture

6 Targeting 16% - 21% Compound Annual Production Growth for MBOEPD 1 (+12% vs. 2012) MBOEPD Severe weather curtailed Q4 production by ~6 MBOEPD % Liquids 62% Liquids ~75% Liquids Q1 Q2 Q3 Q4 2014E 2015E 2016E % Liquids 65% Liquids Expect production to more than double by 2018 (compared to 2013 production) 1) All periods reflect Alaska and Barnett Shale as discontinued operations 2) Strip prices assumed to average $90/BBL and $4.00/MCF in 2014, $85/BBL and $4.00/MCF in 2015 and ) Production reduced after May 31st by ~4 MBOEPD reflecting the divested volumes associated with the closing of the southern Wolfcamp joint venture transaction 6

7 Pioneer s Significant Proved Reserves and Recoverable Resource Potential 1 Proved Reserves + Estimated Net Recoverable Resource Potential of >11 BBOE >22,000 Horizontal Drilling Locations 12/31/13 Proved Reserves: 845 MMBOE 2 Additional Net Recoverable Resource Potential: 10.2 BBOE Eagle Ford Shale 131 MMBOE 130 PUD locations Rockies 119 MMBOE Spraberry/Wolfcamp 432 MMBOE 640 PUD locations Mid-Continent 93 MMBOE Other 70 MMBOE Horizontal Spraberry/Wolfcamp 3,4,5,6 9.6 BBOE 20,500 locations Other MMBOE Expect to replace removed vertical PUDs with 600+ MMBOE of Spraberry/Wolfcamp horizontal reserves during ) All drilling locations shown on a gross basis 2) SEC pricing of $96.82/BBL for oil and $3.67/MMBtu for gas (NYMEX) 3) On PXD s northern acreage, assumes (i) average EURs of 800 MBOE per well for Wolfcamp A and B intervals, 650 MBOE for Wolfcamp D interval and 575 MBOE for Spraberry Shale intervals (Lower Spraberry Shale and Jo Mill Shale), (ii) 100-acre spacing on 50% of total acreage and (iii) 90% WI and 15% royalty 4) On PXD s southern JV acreage, assumes (i) average EUR of 575 MBOE per well, (ii) 207,000 net acres, (iii) 100-acre spacing on 50% of total acreage, (iv) laterals in Wolfcamp A, B, C & D intervals, Lower Spraberry Shale interval and Jo Mill Shale interval and (v) 25% royalty and Pioneer s 60% share 5) Excludes horizontal resource potential from additional intervals (e.g. Clearfork, Middle Spraberry Shale, Atoka, Woodford) and further downspacing opportunities 6) Vertical resource potential that was not converted to horizontal resource potential (e.g. Strawn, Atoka) is not included as PXD has no plans to drill vertical wells in the future except to meet continuous drilling obligations 7) Reflects primarily Upper Eagle Ford Shale potential and 500 additional locations from downspacing to ~300 ; Other net recoverable resource potential excludes Alaska and Barnett Shale 7

8 Midland Basin Horizontal Resource Potential Continues to Grow 75 BBOE Recoverable Resource Potential (Up from 50 BBOE in 2013) Wolfcamp C 2 BBOE Wolfcamp D 13 BBOE Spraberry Shales 14 BBOE Wolfcamp B 27 BBOE Wolfcamp A 19 BBOE 75 BBOE recoverable resource potential in shale intervals where successful horizontal wells have been drilled Assumes 140-acre spacing on 75% of acreage and downspacing to 100-acres on 25% of acreage; additional down-spacing potential exists Additional horizontal potential from other intervals (e.g. Clearfork, Middle Spraberry Shale, Atoka, Woodford) 8

9 Liquidity Position (12/31/13) Net debt (net of cash balance of $393 MM): $2.3 B Unsecured credit facility availability: $1.5 B Net debt-to-book capitalization: 25% Maturities and Balances $455 MM 5.875% $485 MM 6.65% $450 MM 6.875% $450 MM 7.50% $600 MM 3.95% $250 MM 7.20% Undrawn $1.5 B unsecured credit facility Unsecured credit facility matures in 2017 Investment grade rated 1) Excludes issuance discounts and deferred hedge losses of ~$37 MM 9

10 2013 Northern Spraberry/Wolfcamp Horizontal Drilling Appraisal Program 2013 drilling program focused on appraising 6 horizontal shale targets with substantial oil-in-place Wolfcamp D Wolfcamp B Wolfcamp A M. Spraberry Shale Jo Mill L. Spraberry Shale U. Spraberry M. Spraberry Shale Jo Mill Shale Jo Mill Silt L. Spraberry Shale Dean Wolfcamp A Wolfcamp B Wolfcamp C1 Wolfcamp C2 Wolfcamp D Strawn Miss/Atoka 10

11 Recapping Pioneer s 2013 Northern Spraberry/Wolfcamp Program Increased horizontal rig count from 1 rig to 5 rigs mid-2013 Placed 21 horizontal wells on production during 2013 Well Count Interval Avg. 24-hr Peak IP (BOEPD) Peak 30-day Avg. Rate (BOEPD) 9 Wolfcamp B 1,850 1,149 1 Wolfcamp A 1,712 1,122 Pioneer s Northern Spraberry/Wolfcamp Acreage Jo Mill Lower Spraberry Wolfcamp A Wolfcamp B Wolfcamp D 4 Wolfcamp D 2, Lower Spraberry Shale Jo Mill Shale 486 Not yet achieved Not yet achieved 1 Successfully appraised 4 of 6 stacked intervals Well results have confirmed geologic maps Middle Spraberry Shale interval appraisal underway 2013 program included extensive science activity (coring, open-hole logging, micro-seismic and 3-D seismic) 1) Both Jo Mill Shale wells incurred mechanical problems during completion and have subsequently been shut-in pending remedial action 11

12 BOEPD Pioneer s First 6 Northern Horizontal Wolfcamp B and Wolfcamp A Shale Wells 1 E.T. O'Daniel 1H Wolfcamp B (Midland County); 9,229 lateral Cumulative production: 157 MBOE (75% oil) Updated as of 3/20 Scharbauer Ranch #202H Wolfcamp B (Martin County); 8,342 lateral Cumulative production: 70 MBOE (73% oil) DL Hutt C #3H Wolfcamp B (Midland County); 7,142 lateral Cumulative production: 108 MBOE (73% oil) 3,000 2,000 1,000 DL Hutt C #2H Wolfcamp A (Midland County); 7,380 lateral Cumulative production: 160 MBOE (76% oil) Mabee K #1H Wolfcamp B (Martin County); 6,671 lateral Cumulative production: 113 MBOE (71% oil) 2 DL Hutt C #1H Wolfcamp B (Midland County); 7,380 lateral Cumulative production: 205 MBOE (73% oil) MMBOE 800 MBOE Days Production data supports EURs for wells with ~7,000 lateral lengths of 1 MMBOE for Wolfcamp B wells and 800 MBOE for Wolfcamp A wells in Midland County and 800 MBOE for Wolfcamp B wells in Martin County 1) Daily production normalized for operational shut-ins 2) Mabee K #1H shut-in for offset frac; recently placed back on production and currently cleaning up; oil production is slowly recovering to pre-frac levels 12

13 BOEPD Pioneer s First 4 Northern Horizontal Wolfcamp D Shale Wells 1 University H Wolfcamp D (Andrews County); 7,382 lateral Cumulative production: 64 MBOE (69% oil) Updated as of 3/20 E.T. O Daniel #2H Wolfcamp D (Midland County); 9,112 lateral Cumulative production: 108 MBOE (70% oil) 3,000 2,000 1,000 Scharbauer Ranch #201H Wolfcamp D (Martin County); 7,862 lateral Cumulative production: 85 MBOE (60% oil) DL Hutt C #4H Wolfcamp D (Midland County); 6,962 lateral Cumulative production: 84 MBOE (71% oil) MBOE 650 MBOE Days Production data supports EURs of 650 MBOE to 800 MBOE for Wolfcamp D wells in Midland, Martin and Andrews counties with ~7,000 lateral lengths 1) Daily production normalized for operational shut-ins 13

14 BOEPD Pioneer s Northern Horizontal Lower Spraberry Shale Wells 1 Flanagan 14 Lloyd A #21H (Glasscock County) 7,212 lateral; Cumulative production: 60 MBOE (85% oil) Updated as of 3/20 Hutt C #21H (Midland County) 6,662 lateral; Cumulative production: 22 MBOE (79% oil) University 7-43 #16H (Andrews County) 7,502 lateral; Cumulative production: 65 MBOE (83% oil) 2,000 1,000 1st ESP Installed Mabee K #10H (Martin County) 4,982 lateral; Cumulative production: 45 MBOE (89% oil) Scharbauer Ranch #501H (Martin County) 7,502 lateral; Cumulative production: 63 MBOE (83% oil) MMBOE 800 MBOE 575 MBOE Shut-in due to severe weather Lower Spraberry Shale wells typically take days to reach a peak rate Days Lower Spraberry Shale interval contains among the highest oil-in-place (40 MMBOE 60 MMBOE per section) of all Spraberry/Wolfcamp Shale intervals; 24-hour peak IP rates average 84% oil content Early production data suggests EURs for these wells will be 575 MBOE to 800 MBOE 1) Daily production normalized for operational shut-ins 14

15 BOEPD Pioneer s Original Two Horizontal Giddings Wells (Average) 1 1,000 Updated as of 3/20 Giddings #2041H & Giddings #2073H Wolfcamp B wells (Upton County) ~5,300 laterals; Average cumulative production per well: 208 MBOE (70% oil) MBOE 650 MBOE Days More than two years of production data for the original two 5,300 Giddings Wolfcamp B horizontal wells supports an average EUR of 725 MBOE (Equates to an average EUR of 950 MBOE for 7,000 laterals) 1) Daily production normalized for operational shut-ins 15

16 Northern Horizontal Well Economics 1,2 45% - 100% BTAX IRR 45% - 95% 100+% 100+% Lower Spraberry Shale Wolfcamp D Martin County Wolfcamp B & Midland County Wolfcamp A Midland County Wolfcamp B EUR (MBOE) ,000 D&C Cost ($MM) $7.5 $8.5 $8.0 $8.0 Payout Years ) Pricing: $90 oil / $4 gas 2) Reflects 7,000 lateral length and single well drilling cost 16

17 Northern Spraberry/Wolfcamp: Focused on Growing Production in 2014 Transitioning from a horizontal appraisal program to a horizontal development program during 2014 Increased horizontal rig count from 5 rigs at YE 2013 to 16 rigs during Q Expect to spud ~140 horizontal wells during 2014 with average lateral length of ~8,200 ~90% will be Wolfcamp A, B and D interval wells; ~10% will be Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale) Well mix could include more Spraberry Shale wells if strong performance continues Science activity reduced compared to 2013 Utilizing 3-well pads with spud-to-pop times of 145 days 3-well pads and 11 horizontal rigs added in Q1 will result in 2H-weighted production growth 2014 horizontal drilling program cost per well: $8.5 MM to $9.0 MM Vertical rig count reduced from 15 rigs to 11 rigs at YE 2013 Vertical rig count being used to meet continuous drilling obligations Expect to drill ~200 vertical wells during

18 Southern Wolfcamp JV: Focused on Growing Production in drilling plan calls for spudding ~115 horizontal wells compared to ~100 horizontal wells in 2013 Average lateral length will be increased by 13% from 8,300 feet in 2013 to 9,400 feet in 2014 Utilizing 3-well pads Expect to drill ~2/3rds Wolfcamp B interval wells; remainder is a mix of Wolfcamp A, C and D interval wells 2014 drilling program focused on higherreturn areas in northern Upton and Reagan counties (includes Giddings and University Block 2) 2014 horizontal drilling program cost per well: ~$8.0 MM Expanding downspacing tests in several areas Joint Venture Area (Wolfcamp and deeper intervals) 18

19 Spraberry/Wolfcamp Production Outlook Spraberry/Wolfcamp Net Production 1 (MBOEPD) MBOEPD Horizontal Vertical Q4 production curtailed by ~5 MBOEPD due to MBOEPD severe winter weather Despite severe winter weather, horizontal Spraberry/Wolfcamp Shale production grew from 8 MBOEPD in Q3 to 14 MBOEPD in Q4 Placed 34 horizontal wells on production in Q4; predominately weighted towards first half of Q drilling program ~250 horizontal wells 2012 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q E o Utilizing 3-well pads and adding significant horizontal rigs during Q1 will result in 2Hweighted production growth ~200 vertical wells o Results in vertical production decline of ~10% 1) Includes production from Spraberry vertical wells and horizontal Wolfcamp Shale and Spraberry Shale wells 2) Production reduced after May 31 st by ~4 MBOEPD reflecting the divested volumes associated with the closing of the southern Wolfcamp joint venture transaction 19

20 Eagle Ford Shale Downspacing and Staggered Tests Continue Initially downspaced from 1,000 to 500 between wells across liquidsrich acreage position Added ~300 locations Further downspacing and staggered laterals testing underway: Early results from initial 300' well downspacing and staggered test in Lower Eagle Ford Shale continue to be encouraging; wells performing in line with offset 500 wells Wells currently being drilled to test downspacing and staggered to 175 o Some areas will include Lower Eagle Ford Shale only; others will be a combination of the Lower and Upper intervals Potential to add 300 to 400 incremental locations Dewitt Initial Lower Eagle Ford Shale Test Atascosa Additional 175 to 300 downspacing and staggered opportunities exist in 3 areas (3 tests underway) McMullen Dry Gas Window Condensate Window Oil Window 20

21 Upper Eagle Ford Shale Test Update Daily Norm MCFE/1000 Results from initial test continue to be encouraging; production in line with offset Lower Eagle Ford Shale wells ~25% of acreage prospective Planning to drill 45 Upper Eagle Ford Shale wells in 2014 as part of the downspacing program Upper Eagle Ford Test Dry Gas Window Condensate Window Oil Window Production Performance Upper Eagle Ford Well CGP maintenance Norm Cum MCFE/1000 Lower Eagle Ford Wells Upper Eagle Ford Lower Eagle Ford 21

22 Eagle Ford Shale Completion Optimization Over the past 2 years, PXD has improved its Eagle Ford Shale completion design by: Reducing cluster spacing Increasing the pounds of proppant (white sand) pumped per foot Increasing the barrels of frac fluid pumped per minute in each cluster (BPM) Utilizing combinations of the above Results in 20% to 30% EUR increase with minimal increase in drilling and completion capital Generating before tax returns of ~100% on incremental capital spent Completions designed by well due to varying geology Increasing BPM/Cluster Example 4% Capital Increment, 20% EUR increment, ROR100% Increasing Lb./Foot and Decreasing Cluster Spacing Example 12% Capital Increment, 30% EUR increment, ROR100% Increased BPM/Cluster Wells Original Completion Design (Offset Wells) Increased Lb./foot and Decreased Cluster Spacing Wells Original Completion Design (Offset Wells) 22

23 Eagle Ford Shale Production Outlook Eagle Ford Shale Net Production 1 (MBOEPD) MBOEPD Record Eagle Ford Shale net production of 40 MBOEPD in Q4 38 MBOEPD Placed 41 wells on production in Q4; predominately weighted towards first half of Q4 Expect to drill ~110 liquids-rich wells in program reflects longer laterals and larger fracs compared to % pad drilling in 2014, up from 80% in 2013 Utilizing 3-well and 4-well pads for most of the 2014 drilling program (spud to POP averaging days for 3-well pads 2012 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 and days for 4-well pads) E 1) Reflects Pioneer s ~35% share of gross production 23

24 PXD Investment Highlights U.S. asset base High oil exposure from proved reserves + estimated net resource potential of >11 BBOE Drilling program focused in liquids and resource rich core assets in Texas Horizontal Spraberry/Wolfcamp Shale Spraberry vertical Eagle Ford Shale Strong production growth profile Vertical integration substantially improving execution and returns Attractive derivative positions protect margins Strong investment grade financial position 24

25 Appendix 25

26 Pioneer Large Independent U.S. E&P Company Total Enterprise Value ($B) ~$ Operating Cash Flow ($B) $ Drilling Expenditures ($B) $ Drillbit F&D ($/BOE) $ Production 63% Liquids (MBOEPD) Reserve Replacement (%) 211% YE 2013 Proved Reserves (BBOE) 0.8 Raton Hugoton West Panhandle Northern Spraberry/Wolfcamp Southern Wolfcamp JV Area Operating Areas Dallas Headquarters Eagle Ford Shale 26

27 Production Costs (per BOE) 1 Workovers Production & Ad Valorem Taxes Third Party Transportation LOE Natural Gas Processing $3.24 $3.61 $1.40 $7.93 $0.99 $3.44 $1.66 $1.56 $3.52 $7.69 $7.62 $8.03 $14.17 $0.69 $13.36 $0.52 $14.04 $14.08 $13.77 decreased compared to Q3 Q production costs $0.88 $ $0.59 $0.25 Q4 12 Q1 13 $0.16 Q2 13 $3.09 $2.01 $1.03 $(0.08) Q3 13 $8.64 $0.08 Q4 13 LOE increased primarily due to one-time repair costs associated with damage caused by severe winter weather 3 rd party transportation decreased primarily due to adjustments related to Q3 transportation of Eagle Ford Shale production Ad valorem tax payments lower than anticipated Reduced workover activity 1) All periods presented have been restated to exclude discontinued operations 27

28 Pioneer s YE 2013 Proved Reserves 1 Added 141 MMBOE from the drillbit, or 211% of fullyear production, at a drillbit F&D cost of $19.70 per BOE 2 Reflects significant drilling campaigns in horizontal Spraberry/Wolfcamp Shale and Eagle Ford Shale plays Reserve mix 100% U.S. 40% oil / 22% NGLs / 38% gas 81% PD / 19% PUD Proved Reserves / Production: ~13 years PD Reserves / Production: ~10 years Year-end 13 Proved Reserves (MMBOE) Spraberry/Wolfcamp 432 Eagle Ford 131 Raton 119 Mid-Continent 93 Other 70 Total 845 1) Reflects 2013 SEC pricing (12-month average) of $96.82/BBL for oil and $3.67/MMBTU for gas (NYMEX) as compared to 2012 SEC pricing of $94.84/BBL for oil and $2.76/MMBTU for gas (NYMEX) 2) Excludes PUDs removed (319 MMBOE) and positive price revisions (30 MMBOE) 28

29 Production (MBOEPD) Q4 12 Q1 13 Q2 13 Q3 13 Q4 13 Spraberry/Wolfcamp Eagle Ford Shale Raton Mid-Continent South Texas Other Total Cont. Ops Barnett Alaska Total Incl. Disc. Ops ) Q3 production was negatively impacted by the conveyance of ~4 MBOEPD on May 31 st to Sinochem as part of JV agreement 2) Q4 production was negatively impacted by ~5 MBOEPD due to severe winter weather 29

30 PXD Production By Commodity By Area Q4 '12 Q1 '13 Q2 '13 Q3 '13 Q4 '13 Spraberry/Wolfcamp Oil (BOPD) 46,540 52,694 52,595 51,903 52,957 NGL (BOEPD) 11,262 12,864 13,919 16,200 16,251 Gas (M CFD) 64,607 58,653 83,021 62,939 65,863 Total (BOEPD) 68,570 75,333 80,351 78,593 80,186 Eagle Ford Oil (BOPD) 11,671 12,741 13,868 12,399 15,922 NGL (BOEPD) 9,462 10,133 10,212 10,080 11,252 Gas (M CFD) 81,823 86,305 82,765 74,468 78,448 Total (BOEPD) 34,770 37,257 37,874 34,889 40,248 Raton Oil (BOPD) NGL (BOEPD) Gas (M CFD) 144, , , , ,077 Total (BOEPD) 24,041 23,060 22,682 22,322 21,679 Mid-Continent Oil (BOPD) 3,063 3,202 2,902 3,081 2,896 NGL (BOEPD) 7,466 6,511 6,740 7,359 6,589 Gas (M CFD) 41,398 41,250 39,874 40,535 40,249 Total (BOEPD) 17,429 16,589 16,288 17,195 16,193 South Texas Oil (BOPD) NGL (BOEPD) Gas (M CFD) 34,037 31,609 31,208 31,509 28,438 Total (BOEPD) 5,740 5,349 5,273 5,486 5,043 Other Oil (BOPD) NGL (BOEPD) Gas (M CFD) 3,539 3,502 3,306 3,044 2,994 Total (BOEPD) 1,101 1, Total Continuing Ops Oil (BOPD) 61,393 68,787 69,500 67,674 72,129 NGL (BOEPD) 28,649 29,951 31,232 34,009 34,430 Gas (M CFD) 369, , , , ,070 Total (BOEPD) 151, , , , ,238 Barnett Oil (BOPD) 1,574 1,445 1,364 1,547 1,611 NGL (BOEPD) 3,289 3,038 3,184 3,354 3,191 Gas (M CFD) 25,168 24,159 24,061 21,396 24,177 Total (BOEPD) 9,058 8,510 8,558 8,467 8,831 Alaska Oil (BOPD) 4,102 3,707 4,209 4,723 4,154 NGL (BOEPD) Gas (MCFD) Total (BOEPD) 4,102 3,707 4,209 4,723 4,154 Total including Oil (BOPD) 65,495 72,494 73,709 72,397 77,894 Discountinued Ops NGL (BOEPD) 28,649 29,951 31,232 34,009 37,621 Gas (M CFD) 369, , , , ,247 Total (BOEPD) 155, , , , ,223 30

31 Derivative Philosophy Continue to use derivatives to mitigate commodity price exposure in order to ensure funding for development programs and to maintain strong financial position Target >50% on rolling 3 year basis Continue to use a variety of derivative instruments, but focus will be on providing floor protection while retaining upside; primary derivative instruments will be: Collars Collars with short puts (three-way collars) Puts Enter derivative agreements only with counterparties that are A rated or better Actively monitor credit exposure to each counterparty and counterparty credit trends No margin requirements with counterparties 31

32 Open Commodity Derivative Positions as of 2/6/2014 Oil Q Q Q Q Swaps WTI (BPD) 10,000 10,000 10,000 10, NYMEX WTI Price ($/BBL) $ $ $ $ Three Way Collars (BPD) 1 69,000 69,000 69,000 69,000 85,000 25,000 NYMEX Call Price ($/BBL) $ $ $ $ $ $ NYMEX Put Price ($/BBL) $ $ $ $ $ $ NYMEX Short Put Price ($/BBL) $ $ $ $ $ $ % Total Oil Production ~95% ~95% ~85% ~75% ~70% ~15% Oil Basis Protection Q Q Q Q Spraberry Fixed Differential 2 31,000 33,000 34,000 35,000 35,000 35,000 Price Differential ($/BBL) $ (1.75) $ (1.75) $ (1.75) $ (1.75) $ (1.75) $ (1.75) Oil coverage: ~90% in 2014, ~70% in 2015 and ~15% in ) When NYMEX price is above call price, PXD receives call price. When NYMEX price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the short put price, PXD receives put price. When NYMEX price is below the short put price, PXD receives NYMEX price plus the difference between the short put price and put price 2) Market transaction representing Cushing to Midland differential; not a derivative 32

33 Open Commodity Derivative Positions as of 2/6/2014 Natural Gasoline Q Q Q Q Three Way Collars (BPD) 1,2 1,000 1,000 1,000 1,000 - Mont Belvieu Call Price ($/BBL) $ $ $ $ Mont Belvieu Put Price ($/BBL) $ $ $ $ Mont Belvieu Short Put Price ($/BBL) $ $ $ $ Ethane Q Q Q Q Collars (BPD) 3 3,000 3,000 3,000 3,000 - Mont Belvieu Call Price ($/BBL) $ $ $ $ Mont Belvieu Put Price ($/BBL) $ $ $ $ Propane Q Q Q Q Swaps (BPD) ,000 3,000 1,674 - Mont Belvieu Swap Price ($/BBL) $ $ $ $ % Total NGL Production ~10% ~15% ~15% ~15% - % Total Liquids ~75% ~70% ~65% ~60% - 1) When NYMEX price is above call price, PXD receives call price. When NYMEX price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the short put price, PXD receives put price. When NYMEX price is below the short put price, PXD receives NYMEX price plus the difference between the short put price and put price 2) Represent collar contracts with short puts that reduce price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices 3) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices 4) Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices 33

34 Open Commodity Derivative Positions as of 2/6/2014 Gas Q Q Q Q Swaps - (MMBTUPD) 195, , , ,000 20,000 - NYMEX Price ($/MMBTU) 1 $ 4.04 $ 4.04 $ 4.04 $ 4.04 $ Three Way Collars (MMBTUPD) 1,2 115, , , , ,000 20,000 NYMEX Call Price ($/MMBTU) $ 4.70 $ 4.70 $ 4.70 $ 4.70 $ 5.07 $ 5.36 NYMEX Put Price ($/MMBTU) $ 4.00 $ 4.00 $ 4.00 $ 4.00 $ 4.00 $ 4.00 NYMEX Short Put Price ($/MMBTU) $ 3.00 $ 3.00 $ 3.00 $ 3.00 $ 3.00 $ 3.00 % Total Gas Production ~90% ~85% ~85% ~85% ~80% ~5% Gas Basis Swaps Q Q Q Q Spraberry (MMBTUPD) 10,000 10,000 10,000 10,000 10,000 - Price Differential ($/MMBTU) $ (0.15) $ (0.15) $ (0.15) $ (0.15) $ (0.13) - Mid-Continent (MMBTUPD) 65, , , ,000 20,000 - Price Differential ($/MMBTU) $ (0.21) $ (0.23) $ (0.22) $ (0.22) $ (0.21) - Gas coverage: ~85% in 2014 and ~80% in ) Represents the NYMEX Henry Hub index price or approximate NYMEX price based on historical differentials to the index price at the time the derivative was entered into 2) When NYMEX price is above call price, PXD receives call price. When NYMEX price is between put price and call price, PXD receives NYMEX price. When NYMEX price is between the put price and the short put price, PXD receives put price. When NYMEX price is below the short put price, PXD receives NYMEX price plus the difference between short put price and put price 34

35 Realized Price ($/BBL) Three-Way Collars ($75 by $90 by $135 Example) Unhedged realization Hedged realization $ NYMEX Price $ $ Potential Opportunity Loss $ $ Short put at $75/BBL Long put at $90/BBL Realized Price Short call at $135/BBL $ $ $90.00 $80.00 Realize NYMEX price plus $15/BBL (difference between long put and short put) Realize $90/BBL Realize NYMEX price Realize $135/BBL $70.00 $60.00 $50.00 $50.00 $60.00 $70.00 $80.00 $90.00 $ $ $ $ $ $ $ NYMEX Oil ($/BBL) Three way collars protect downside while providing better upside exposure than traditional collars or swaps 35

36 Pioneer Focusing Capex in Highest Margin Assets 2013E Cash Margins ($/BOE ex-hedges) 1,2 Assumes $98.00/BBL WTI Crude and $3.70/MCF Gas PXD 2013E % Liquids Production >50% <50% Peer Average = $34.50/BOE 3 1) Source: 2013E analyst estimates from Citi, JP Morgan, Simmons & Co, ISI and Credit Suisse; PXD internal 2013E margins for Permian horizontal assets 2) Cash margin is revenue excluding hedges minus production costs, taxes and G&A on a BOE basis 3) Excludes PXD and PXD assets 36

37 Geologic Provinces of the Permian Basin PEDERNAL UPLIFT & ROOSEVELT POSITIVE OZONA PLATFORM Basin Basement Uplift Shelf Thrust Belt DEVIL S RIVER UPLIFT Permian Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian ages Spraberry/Wolfcamp Shale and deeper intervals are located in the Midland Basin of the Permian Basin Spraberry/Wolfcamp field was discovered in 1943 with production commencing in

38 Wolfcamp Depositional Model Midland Basin Platform Carbonate Platform Carbonate Shelf Edge Carbonate Land Clastic Detrital Pelagic Sediments CBP Midland Basin Slope Sediments & Reef Talus Carbonate Debris Flows Carbonate Gravity Flows Fluvial - Deltaic Delta Clastic Slope Sediments Silt Cloud in Suspension Anaerobic Zone (Organic-rich Sediments) Basinal Sediments Clastic Gravity Flows Land Midland Marathon Thrust Belt Marathon Thrust Belt Land Glasscock Nose Pelagic Sed. Clastic Slope Land Wolfcamp Map Platform Carbonate Carb Gravity Flow Carbonate Slope Debris Flow Clastic Gravity Flow Older Wolfcamp Clastics North Basin Platform San Simon Channel North Source: Adapted from Handford,

39 Regional Cross Section D-D Successful Horizontal Wells in the Play Future Horizontal Play 13 horizontal play intervals identified (so far) 10 intervals have been tested successfully 3 additional intervals remain to be tested North D D South Spraberry MSS Jo Mill Shale LSS WC-A WC B,C1 WC-D Strawn Miss Woodford Clear Fork Spraberry MSS Jo Mill Shale LSS WC-A WC-Upper B WC-Lower B WC-C WC-D Woodford Miss Ozona Platform Woodford Atoka Horseshoe Atoll Barnettford Calvin Fault Big Lake Fault 39

40 Midland Basin: Stacked Play Potential 200 ft Clear Fork U. Spraberry M. Spraberry Shale Jo Mill Shale Midland Basin Delta log R (excess electrical resistance) Red intervals indicate hydrocarbons Petrophysical analysis indicates significantly more oil in place in the Wolfcamp and Spraberry Shale intervals in the Midland Basin compared to other major U.S. shale oil plays L. Spraberry Shale Dean Eagle Ford Condensate Barnett Combo Niobrara Bakken Marcellus Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Cline Strawn Atoka Barnett Miss Lime Woodford Source: PXD 40

41 Spraberry/Wolfcamp Rig Count Counties: Andrews, Borden, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Irion, Martin, Midland, Mitchell, Reagan, Schleicher, Scurry, Sterling, Tom Green and Upton % Vertical Rigs 61% Vertical Rigs Vertical Rigs 39% Horizontal Rigs (up from 23% in early 2013) 100 4% Horizontal Rigs 50 0 Horizontal Rigs Source: Rig count data provided by Baker Hughes, 2/14/14 41

42 Gross Production (BOEPD) Production Growth Profiles For 3 Largest U.S. Oil Shale Plays 10,000,000 1,000,000 Includes Horizontal Wells Only Eagle Ford 198 Horizontal Rigs (down from 218 rigs in early 2013) 100,000 10,000 Spraberry/Wolfcamp 114 Horizontal Rigs (up from 60 rigs in early 2013) Bakken 168 Horizontal Rigs (down from 176 rigs in early 2013) 1, Months Spraberry/Wolfcamp horizontal growth trajectory similar to Bakken and Eagle Ford Note: Production data is from IHS and represents incremental production for the play beginning when horizontal drilling activity began in earnest; Rig count data from Baker Hughes as of 2/14/14 for selected counties identified on slide 41 for Spraberry/Wolfcamp; Initial month is November 2010 for Spraberry/Wolfcamp, April 2008 for Eagle Ford and January 2003 for Bakken 42

43 Spraberry/Wolfcamp Production History Production (BOEPD) Includes Vertical and Horizontal Wells 600, , ,000 Spraberry/Wolfcamp production has increased ~400,000 BOEPD since , , , , , , ,000 Monthly Production 100,000 50,000 - From 2009 to 2012, production growth primarily attributable to increased vertical activity Post 2012, production growth expected to be driven by horizontal activity Source: IHS Energy through October 2013 for the Spraberry, Credo East, Garden City South and Lin Fields 43

44 Crude Pipeline Capacity to Gulf Coast Permian Basin Crude Takeaway Capacity Cushing Operator Origin Destination Name Capacity Time Frame Plains Permian Cushing Basin 450,000 Oxy Permian Cushing Centurion 75,000 Wink Permian Basin Keystone South Seaway Current Planned Sunoco Permian GC West Texas Gulf 400,000 Kinder Morgan Permian El Paso Wink 120,000 Magellan Permian GC Longhorn 225,000 Total 1,270,000 Magellan Permian GC Longhorn-add 50,000 3Q 2014 Magellan Permian GC BridgeTex 278,000 3Q 2014 Plains Permian Corpus Cactus 200,000 2Q 2015 Sunoco Permian GC Permian Express II 200,000 2Q 2015 GC Market Cushing to Gulf Coast Pipeline Takeaway Operator Origin Destination Name Capacity Time Frame Enbridge/Enterprise Cushing GC Seaway 400,000 Current Transcanada Cushing GC Keystone South 300,000 Enbridge/Enterprise Cushing GC Seaway-add 450,000 2Q 2014 Planned Transcanada Cushing GC Keystone South-add 530,000 3Q-4Q

45 Growing Midstream Infrastructure to Support Production Growth Gas Processing Midkiff / Benedum / Driver Current capacity: 460 MMCFD 1 PXD production makes up ~40% of throughput New Edward plant expected 4Q 2014 (+200 MMCFD) Additional plant expected 4Q 2015 (+200 MMCFD) Sale Ranch Pipeline NGL Takeaway to Mont Belvieu Chaparral & West Texas Pipelines PXD production throughput of ~9 MBPD Lone Star Pipeline 4 MBPD to PXD increasing to Sale Ranch Current capacity: 160 MMCFD1 New Sale Ranch plant expected 3Q 2014 (+200 MMCFD) PXD production makes up ~15% of Sale Ranch throughput Driver Plant Midkiff 16 MBPD by 2020 Connect to all PXD gas processing plants Mont Belvieu fractionation capacity at 1.5 MMBPD Capacity additions of ~1 MMBPD planned during Benedum/Edward PXD Acreage Spraberry Field Existing NGL Pipeline Continuing to expand processing capacity and contracted takeaway to support Pioneer s aggressive production growth 1) Wet gas stream with ~160 BBL/MMSCF NGL yield 45

46 PXD s Vertical Integration Reduces Costs and Enhances Execution Spraberry/Wolfcamp 1 8 horizontal frac fleets (~250,000 HP total) 2 coiled tubing units Well service equipment 2 Brady sand mine Eagle Ford Shale 2 frac fleets (~100,000 HP total) 2 coiled tubing units 2014 frac capacity: ~350,000 HP 1 13 th largest pressure pumping company in North America 1) Includes ~50,000 additional horsepower expected to be added in the Spraberry/Wolfcamp in 3Q ) Includes pulling units, frac tanks, hot oilers, water trucks, blowout preventers, construction equipment and fishing tools 46

47 Reserves Audit, F&D Costs and Reserve Replacement An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10- K for a general description of the concepts included in the SPE's definition of a reserve audit. "Drillbit finding and development cost per BOE," or drillbit F&D cost per BOE, means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates (excluding PUDs removed and price revisions), discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred. Drillbit reserve replacement is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates (excluding PUDs removed and price revisions), discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis. 47

48 Certain Reserve Information Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than reserves, as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as resource potential, net recoverable resource potential, resource base, estimated ultimate recovery, EUR or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC s definitions of proved, probable and possible reserves, and which 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 disclosures in the Company s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company s website at These filings also can be obtained from the SEC by calling SEC