I N V E S T O R P R E S E N T A T I O N D E C E M B E R

Transcription

1 I N V E S T O R P R E S E N T A T I O N D E C E M B E R

2 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 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 perform the Company s drilling and operating activities, access to and availability of transportation, processing, fractionation, refining and export 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, investment instruments and derivative contracts and purchasers of Pioneer s oil, natural gas liquid and gas production, uncertainties about estimates of reserves and resource potential, identification of drilling locations 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 Annual Report on Form 10-K for the year ended December 31, 2016, 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. Accordingly, no assurances can be given that the actual events and results will not be materially different than the anticipated results described in the forward-looking statements. 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 Largest Midland Basin (Spraberry/Wolfcamp) acreage position with decades of oil drilling inventory 800 M gross acres with >20 M drilling locations Low cost with high returns Low average royalty and acreage cost basis 2017 capital program of $2.75 B (~95% Permian) 1 Strong derivatives position protects cash flow Strong investment grade balance sheet Net debt to 2017E operating cash flow: 0.3x 2 Net debt-to-book capitalization : 5% Raton West Panhandle Spraberry/Wolfcamp Active Drilling Areas Spraberry/Wolfcamp Gross Production By Operator 2 (MBOEPD) Dallas Headquarters Eagle Ford Shale Oil 59% 276 MBOEPD Q Production NGL 21% Gas 20% ) July 2017 DrillingInfo data, gross reported oil and wet gas (unallocated 2-stream) 1) Capex excludes acquisitions, asset retirement obligations, capitalized interest, G&G G&A and IT system upgrades 2) As of end-q

4 2017 DRILLING AND OPERATING UPDATE Spraberry/Wolfcamp Recently added 2 rigs to improve operational flexibility by increasing the Company s DUC inventory Once an adequate DUC inventory is built in 2H 2018, the 2 rigs will be used to achieve longer-term production growth targets Consistent with previously discussed plans to add rigs in 2H 2018 Brings total rig count to 20 rigs 16 rigs in northern area and 4 rigs in southern Wolfcamp JV area (60% WI) Expect to place ~230 wells on production in 2017 Utilizing Version 3.0 completions o Testing ~15 wells with Version 3.0+ completions IRRs expected to range from 40% to 75% 1 Successfully utilizing 4-string casing design where necessary Eagle Ford Shale Completing 20 wells (9 DUCs and 11 new drills; 46% WI) Objective of the program is to test longer laterals, wider spacing and higher intensity completions 2 new drills and 9 DUCs were placed on production during Q2 and Q3 9 additional new drills being placed on production during Q4 IRRs expected to range from 30% to 40% 1 1) Based on $50/BBL oil price and $3/MCF gas price 4

5 NYMEX Gas Price ($/MCF) 2017 CAPITAL PROGRAM 1 AND CASH FLOW 2017 capital program of $2.75 B Drilling and Completion Capital: $2.475 B $2.35 B Spraberry/Wolfcamp 2 (~95% of total) o $1.86 B for horizontal drilling program o $265 MM for tank batteries/swds o $115 MM for gas processing facilities o $110 MM for land/science/other $105 MM Eagle Ford Shale o $75 MM for horizontal drilling program o $30 MM for compression/land/other $20 MM Other Assets Other Capital: $275 MM 3 Capital program funded from: Cash flow of $1.9 B at $49.50/BBL oil and $3/MCF gas Cash on hand (including liquid investments) 2017 Cash Flow Sensitivity to Forward Commodity Prices ($ MM) NYMEX Oil Price ($/BBL) Reflects 9 months actual and Q4E prices $49.50/BBL oil and $3/MCF gas 1) Capital spending excludes acquisitions, asset retirement obligations, capitalized interest, G&G G&A and IT system upgrades 2) 2017 budget incorporates remaining JV carry from Sinochem of $30 MM, which was fully utilized in April 3) Includes vertical integration (pressure pumping and well services equipment, water distribution system and sand mine), field facilities and vehicles 5

6 PIONEER S PRODUCTION GROWTH FORECAST Total Net Production MBOEPD MMBOEPD ~700 MBOPD Oil (MBOPD) Q1 Q2 Q3 Q4E 2026E

7 LIQUIDITY POSITION Net debt at the end of Q (reflects cash on hand, including liquid investments, of $2.1 B) Unsecured credit facility availability Net debt-to-book capitalization at the end of Q3 Net debt to 2017E operating cash flow $0.6 B $1.5 B 5% 0.3x Maturities and Balances $450 MM 6.875% $450 MM 7.500% $500 MM 3.450% $600 MM 3.950% $500 MM 4.450% $250 MM 7.200% $1.5 B unsecured credit facility (undrawn as of 9/30/17) Mid-investment grade rated by Moody s, S&P and Fitch 1) Excludes issuance costs and issuance discounts of ~$19 MM 7

8 Breakeven Oil Price ($/BBL) OIL BREAKEVENS BY SHALE PLAY IN NORTH AMERICA $50 $40 $30 $20 $10 $ - Midland Basin considered the top oil shale play in North America with a breakeven oil price of ~$24/BBL Source: Citi Research Report (9/13/2017) Breakeven oil price assumes $3/MMBtu flat gas price 8

9 Breakeven Oil Price ($/BBL) NORTH AMERICAN SHALE PLAY OIL BREAKEVENS BY COMPANY $50 $40 $30 $20 $10 $ - Pioneer s world-class Midland Basin acreage position delivers industry leading breakeven oil price Source: Citi Research Report (9/13/2017) Breakeven oil price assumes $3/MMBtu flat gas price Companies include: APC, CDEV, CHK, CLR, CPE, DVN, ECA, EOG, HES, MRO, NBL, NFX, OAS, PE, SRCI, WLL, WPX, XEC and XOG 9

10 2017 SPRABERRY/WOLFCAMP DRILLING PROGRAM Operating 20 horizontal rigs in the Spraberry/Wolfcamp Version 3.0 completions are the standard design Testing ~15 wells with Version 3.0+ completions Budgeted drilling and completion cost per well: Pioneer s Spraberry/Wolfcamp Acreage Position and 2017 Drilling Areas Northern Area Southern Wolfcamp JV Area Interval Lateral Length Well Cost ($MM) EUR (MMBOE) Wolfcamp B ~10,000 ~$ Wolfcamp A ~9,500 ~$ Lower Spraberry Shale ~9,500 ~$ Horizontal production costs per well: $4/BOE to $5/BOE (includes taxes) IRRs of 40% to 75% assuming Version 3.0 completions and prices of $50/BBL for oil and $3/MCF for gas (includes 2017 tank battery/swd costs) Plan to place ~230 horizontal wells on production in 2017 (~190 wells in northern area and ~40 gross wells in JV area) ~55% Wolfcamp B; ~30% Wolfcamp A; ~15% LSS 10

11 EARLY RESULTS FROM 12 VERSION 3.0+ COMPLETIONS ENCOURAGING North University Area: LSS Cumulative Production (MBOE) 1 Hutt Area: Wolfcamp B Cumulative Production Version 3.0+: 3 wells in Q2 ~9,000 avg. lateral length 50 bbls/ft and 3,000 lbs/ft Updated End October Version 3.0: 24 wells since late-2015 ~8,800 avg. lateral length Cumulative Production (MBOE) 1 Version 3.0+: 3 wells in Q2 ~9,700 avg. lateral length 50 bbls/ft and 3,000 lbs/ft Updated End October Version 3.0: 7 wells since 2016 ~8,300 avg. lateral length South University Area: Wolfcamp B Updated End October Pembrook Area: Wolfcamp B Updated End October Cumulative Production (MBOE) 1 Version 3.0+: 3 wells in Q2 ~9,800 avg. lateral length 67 bbls/ft and 2,500 lbs/ft Version 2.0: 6 wells since mid-2016 ~10,000 avg. lateral length (MBOE/10,000 Lateral) 1,2 Version 3.0+: 3 wells in Q2 ~7,000 avg. lateral length 100 bbls/ft and 5,000 lbs/ft Version 3.0: 26 wells since mid-2016 ~9,500 avg. lateral length 1) Production normalized for shut-ins 2) Cumulative production normalized to a lateral length of 10,000 to account for the differences in lateral length between version 3.0 and version 3.0+ wells in the area 11

12 JO MILL PERFORMANCE ENCOURAGING Jo Mill wells since Q Cumulative Production (MBOE) 1 4 POPs during Q2 2017: ~8,250 avg. lateral length 2 POPs during Q3 2017: Sale Ranch 10H and 12H ~6,900 avg. lateral length Updated End October 5 POPs between Q and Q1 2017: ~6,800 avg. lateral length Jo Mill POP Locations Q3 Jo Mill POPs 11 Jo Mill wells have been POP d since Q new wells POP d during Q3 are showing strong initial results Remaining 9 wells are exhibiting encouraging performance Wells placed on production to date cover a large cross section of Pioneer s acreage Additional Jo Mill wells planned for 2018 drilling program Well cost: ~$7 MM for a 8,500 lateral 1) Production normalized for shut-ins 12

13 SPRABERRY/WOLFCAMP PRODUCTION FORECAST Spraberry/Wolfcamp Net Production (MBOEPD) Q3 production: 231 MBOEPD (+19 MBOEPD, or 9%, vs. Q2) wells placed on production in Q3 o 49 wells in northern area and 12 wells in the southern Wolfcamp JV area 160 wells placed on production through Q production outlook 66 Horizontal Expect to grow 30% - 32% in 2017 Expect to place ~230 wells on production Q4 production outlook Vertical Q1 Q2 Q3 Q4E Expect to POP ~70 wells in Q4 weighted evenly across the quarter ) Includes horizontal and vertical production from Pioneer s northern acreage and the southern Wolfcamp joint venture area (60% Pioneer/40% Sinochem) 13

14 2017 EAGLE FORD SHALE DRILLING PROGRAM Completing 20 horizontal wells in the Eagle Ford Shale Includes 9 DUCs that are testing higher intensity Pioneer s Eagle Ford Shale completions and 11 new drills that are testing longer laterals with wider spacing and higher intensity completions D&C cost of new drills: $9.6 MM (gross) IRRs expected to range from 30% to 40% 1 Summary of Design Changes: Previous Design Drilling program moderates production decline Expecting EURs on new drills to average 1.3 MMBOE 2017 vs decline expected to be ~35% 2017 New Well Testing Longer Laterals ~5,200 ~7,500 Wider Well Spacing ~300 ~550 Tighter Cluster Spacing Increased Proppant Concentration 1,200 lbs/ft 2,000 lbs/ft 2017 activity ~59,000 net acres in Eagle Ford Shale 2 100% held-by-production Q3 production: 21 MBOEPD (34% condensate, 34% NGLs and 32% gas) 1) Based on $50/BBL oil price and $3/MCF gas price 2) Reflects planned divestment of ~10,500 net acres 14

15 EAGLE FORD WELL PERFORMANCE TO DATE Pioneer s Eagle Ford Shale 2017 New Drills: 2 wells in Q3 ~6,800 avg. lateral length ~550 avg. well spacing Completion: 40 bbls/ft, 2,000 lbs/ft 2017 DUCs: 9 wells in Q2 and Q3 ~7,400 avg. lateral length ~300 avg. well spacing Completion: 45 bbls/ft, 2,000 lbs/ft Updated End October Q4 POPs Q2 and Q3 POPs POPs: 131 wells since Q ~5,300 avg. lateral length ~300 avg. well spacing Standard completion: 25 bbls/ft, 1,200 lbs/ft DUCs New Drills Average cumulative production per well from new drills and DUCs more than double average cumulative production per well from all 2015 and 2016 POPs 9 DUCs POP d during Q2 and Q new drills POP d during Q3; remaining 9 wells being POP d during Q4 15

16 PIONEER S 10-YEAR VISION Targeting to grow production to 1+ MMBOEPD in 2026 Reflects organic compound annual production growth of 15%+ drilling high-return wells Growth driven by world-class Spraberry/Wolfcamp asset low cost with high returns Vertical integration and technology enhancements support execution Financial expectations: Achieve positive free cash flow (cash flow breakeven at oil price of ~$50/BBL in 2020) Grow cash flow at a compound annual rate of >20% Protect cash flow with an active derivatives program Maintain net debt to cash flow below 1.0x Improve corporate returns; include return and per-share growth metrics in executive compensation On pace to deliver 10-year oil growth target of ~700 MBOPD Total 2026 production forecasted to be 1+ MMBOEPD as a result of higher than expected NGL and gas growth 16

17 A P P E N D I X 17

18 PIONEER S AREAS OF OPERATIONS Current Total Enterprise Value ($B) ~$27 Q Production (MBOEPD) Drillbit F&D ($/BOE) $ Proved Developed F&D ($/BOE) $ Reserve Replacement (%) 232% YE 2016 Proved Reserves (BBOE) 0.7 Raton West Panhandle Spraberry/Wolfcamp Dallas Headquarters Active Drilling Areas Eagle Ford Shale 18

19 PRODUCTION BY COMMODITY BY AREA Q3 '16 Q4 '16 Q1 '17 Q2 '17 Q3 '17 Spraberry/Wolfcamp Oil (BOPD) 120, , , , ,261 NGL (BOEPD) 34,631 31,637 36,529 42,176 47,678 Gas (MCFPD) 144, , , , ,552 Total (BOEPD) 179, , , , ,364 Eagle Ford Oil (BOPD) 10,567 9,047 7,871 6,280 6,957 NGL (BOEPD) 10,659 8,830 6,799 6,491 6,981 Gas (MCFPD) 64,498 55,018 45,070 39,530 40,776 Total (BOEPD) 31,976 27,047 22,182 19,359 20,734 Raton Oil (BOPD) NGL (BOEPD) Gas (MCFPD) 95,200 92,937 89,959 89,228 88,490 Total (BOEPD) 15,867 15,490 14,993 14,871 14,748 West Panhandle Oil (BOPD) 1,745 2,311 1,997 2,061 1,181 NGL (BOEPD) 3,641 3,566 3,344 4,371 2,466 Gas (MCFPD) 7,541 5,041 5,390 7,936 5,266 Total (BOEPD) 6,642 6,717 6,240 7,755 4,525 South Texas Oil (BOPD) 1,261 1,238 1,226 1,230 1,235 NGL (BOEPD) Gas (MCFPD) 20,902 20,607 19,565 18,346 17,225 Total (BOEPD) 5,047 4,893 4,641 4,517 4,325 Other Oil (BOPD) NGL (BOEPD) Gas (MCFPD) Total (BOEPD) Total Operations Oil (BOPD) 134, , , , ,634 NGL (BOEPD) 49,235 44,255 46,828 53,268 57,346 Gas (MCFPD) 332, , , , ,384 Total (BOEPD) 238, , , , ,711 19

20 CASH MARGINS BY ASSET Q Cash Margin by Asset ($ per BOE) Permian Horizontals Permian Verticals Eagle Ford Other Assets Total Company Realized price (ex-hedges) $ $ $ $ $ Production costs (1.85) (18.08) (11.90) (12.87) 2 (6.01) Production and ad valorem taxes (2.32) (2.04) (1.30) (1.08) (2.10) Cash margin $ $ $ $ 5.81 $ % Oil 67% 61% 34% 10% 59% 1) Includes lease operating expense, third-party transportation, workover expense and net natural gas processing cost 2) Includes the impact of significant unplanned downtime in West Panhandle field 20

21 PRODUCTION COSTS (PER BOE) Workovers Production & Ad Valorem Taxes Third-Party Transportation LOE $8.42 $8.20 $8.38 $8.11 $7.85 $0.46 $0.59 $0.76 $0.37 $1.02 $1.43 $1.78 $2.11 $2.19 $2.10 $1.31 $1.13 $1.01 $0.82 $0.80 $4.72 $4.99 $4.99 $4.79 $4.48 Q compared to Q2 2017: LOE declined due to increasing production attributable to lower cost horizontal Spraberry/Wolfcamp wells and cost reduction initiatives Increased Spraberry vertical well workover activity in Q3 Natural Gas Processing $0.02 ($0.16) ($0.28) Q3 16 Q4 16 Q1 17 ($0.18) Q2 17 ($0.29) Q

22 CASING DESIGN COMPARISON 3-String 4-String 13 3/8 Surface Casing 13 3/8 Surface Casing 9 5/8 Intermediate Casing Water Disposal Zone (Higher Pressures) 9 5/8 Intermediate Casing Clearfork - Spraberry (Lower Pressures) 7 5/8 Casing 5 1/2 Production Casing 5 1/2 Production Casing 4-string casing design eliminates the challenges of balancing mud weights between high and low pressured intervals experienced when utilizing a 3-string casing design After surface casing is set to protect the water table, intermediate casing is set from the surface through the higherpressured water disposal zone Incremental casing string is set below the water disposal zone through the lower-pressured Clearfork and Spraberry intervals Production casing is set from the surface to the horizontal interval being completed 22

23 BENEFITS OF WATER REUSE VS. DISPOSAL Treatment & Blending Tank Battery Water Disposal SWD Facility Tank Battery Water Reuse Existing Storage Pond Produced Water Pioneer s water infrastructure provides a unique opportunity to reuse produced water Benefits of reusing produced water include: Water Disposal Produced Water Water for Completion Reduced disposal costs Reduction of higher pressures in water disposal zone; could eventually allow a return to a 3-string casing design in certain areas Reduced use of fresh water for completions Increasing water reuse in 2H 2017 in areas where water infrastructure is in place and drilling challenges have been the most prevalent 23

24 GAS PROCESSING AND VERTICAL INTEGRATION SUPPORT EXECUTION Gas Processing 2017 spending expected to be ~$115 MM; includes ~$70 MM for gathering system compression and new connections and ~$45 MM for capacity additions Brady Sand Mine 2017 spending expected to be ~$30 MM to complete optimization of existing facilities to improve yields and reduce overall supply costs Pioneer Pumping Services 2017 spending expected to be ~$45 MM for fleet upgrades and maintenance 24

25 EXPANDING OIL PIPELINE COMMITMENTS TO MEET EXPECTED SPRABERRY/WOLFCAMP VOLUME GROWTH Midland Houston Corpus Christi Nederland Pioneer is currently delivering >100 MBOPD of Spraberry/Wolfcamp oil to the Gulf Coast under firm pipeline contracts Longer-term target is to move 70% - 80% of forecasted net oil production with additional firm pipeline transport commitments New pipeline transport commitments increase access to international markets and U.S refinery market Gulf Coast Refining Capacity: ~7 MMBOPD Gulf Coast Oil Export Capacity (Industry): 2-3 MMBOPD Current Export Volumes (Industry): ~2 MMBOPD 25

26 CRUDE PIPELINE CAPACITY TO GULF COAST Major Permian Crude Pipeline Takeaway Operator Origin Destination Pipeline Capacity (BOPD) Cushing Plains Permian Cushing Basin 450,000 Oxy Permian Cushing Centurion 75,000 Sunoco Permian GC West Texas Gulf 400,000 Kinder Morgan Permian El Paso Wink 135,000 Magellan Permian GC Longhorn 275,000 Current Magellan Permian GC BridgeTex 360,000 Wink Permian Basin Gulf Coast Seaway Plains Permian Corpus Cactus 390,000 Sunoco Permian GC Permian Express II 300,000 Sunoco Permian GC Permian Express III 100,000 Total 2,485,000 Operator Origin Destination Pipeline Capacity (BOPD) Q Enterprise Midland GC Midland to Sealy 450,000 Q Sunoco Permian GC Permian Express III 200,000 GC Market Current Cushing to Gulf Coast Pipeline Takeaway Operator Origin Destination Pipeline Capacity (BOPD) Enbridge/Enterprise Cushing GC Seaway 850,000 Transcanada Cushing GC Gulf Coast 700,000 Current Permian surplus oil takeaway capacity to the Gulf Coast estimated at ~200 MBOPD, taking into account local refinery demand With the announcement of the new Enterprise pipeline to the Gulf Coast in Q and the expansions of Bridgetex, Cactus and Permian Express in 2H 2017, Pioneer expects sufficient Permian oil takeaway capacity through at least

27 SPRABERRY/WOLFCAMP MIDSTREAM INFRASTRUCTURE Gas Processing Targa System Pipeline NGL Takeaway to Mont Belvieu PXD has 27% interest Current capacity: 855 MMCFD 1 PXD production makes up ~40% of throughput Joyce Plant expected to be online in Q (200 MMCFD) and Johnson Plant in Q (200 MMCFD) WTG (Martin County and Sale Ranch plants) PXD has 30% interest Current capacity: 320 MMCFD 2 PXD production makes up ~25% of throughput Buffalo Driver Johnson Benedum Edward Joyce Sale Ranch / Martin County Midkiff PXD Acreage Existing NGL Pipeline Chaparral & West Texas Pipelines PXD production throughput of ~13 MBPD Lone Star Pipeline PXD production throughput of ~40 MBPD Connect to all PXD gas processing plants Mont Belvieu fractionation capacity at ~2.1 MMBPD Processing and takeaway capacity sufficient to support Pioneer s production in the Midland Basin 1) Wet gas stream with ~160 BBL/MMSCF NGL yield 2) Wet gas stream with ~135 BBL/MMSCF NGL yield 27

28 INNOVATION WILL BE A KEY CONTRIBUTOR TO ACHIEVING PIONEER S 10-YEAR VISION New technology initiatives are focused on improving productivity 4-D fracture propagation modeling Machine learning and artificial intelligence Predictive analytics Automation 4-D fracture propagation modeling Development and use of advanced materials (e.g. fluid end metallurgy) Dynamic drill string modeling Real-time drilling prediction software State-of-the-art downhole tools Advanced subsurface measurement (e.g. fiber optics) Fluid end metallurgy Dynamic drill string modeling Large-scale produced water recycling Partnering with national labs and service companies 28

29 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 Continue to use a variety of derivative instruments, but focus will be on providing floor protection while retaining upside; primary derivative instruments will be: Swaps Collars with short puts (three-way collars) 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 29

30 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 10/31/17 Oil Q Collars (BPD) 6,000 3,000 NYMEX Short Call Price ($/BBL) $70.40 $58.05 NYMEX Put Price ($/BBL) $50.00 $45.00 Three Way Collars (BPD) 1 155, ,781 NYMEX Call Price ($/BBL) $62.12 $57.72 NYMEX Put Price ($/BBL) $49.82 $47.36 NYMEX Short Put Price ($/BBL) $41.02 $37.32 % Total Oil Production >90% >80% Oil coverage: >90% for the remainder of 2017 and >80% in ) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price 30

31 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 10/31/17 Ethane Q Collars (BPD) 1 3, Mont Belvieu Call Price ($/BBL) $11.83 $ - $ - Mont Belvieu Put Price ($/BBL) $8.68 $ - $ - Frac Spread (BPD) 2 2,500 2,500 2,500 MMBTUPD Equivalent 6,920 6,920 6,920 Price differential to NYMEX ($/MMBTU) $1.60 $1.60 $1.60 Propane Swaps (BPD) 3 1, Mont Belvieu Swap Prices ($/BBL) $ $ - $ - % Total NGL Production >10% <5% <5% 1)Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices 2)Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swaps fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane 3)Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas posted prices 31

32 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 10/31/17 Gas Q Swaps (MMBTUPD) 1-82,740 - NYMEX Price ($/MMBTU) $ - $3.03 $ - Three Way Collars (MMBTUPD) 1,2 300,000 62,329 - NYMEX Call Price ($/MMBTU) $3.60 $3.56 $ - NYMEX Put Price ($/MMBTU) $2.96 $2.91 $ - NYMEX Short Put Price ($/MMBTU) $2.47 $2.37 $ - % Total Gas Production >85% >35% Gas Basis Swaps Q Permian Basin (MMBTUPD) 39,783 56,603 80,000 Price Differential to SoCal ($/MMBTU) $0.36 $0.32 $0.31 Mid-Continent (MMBTUPD) 45, Price Differential to NYMEX ($/MMBTU) $(0.32) $ - $ - Gas coverage: >85% for the remainder of 2017 and >35% for )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, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between put price and short put price 32

33 Realized Price ($/BBL) THREE-WAY COLLARS ($40 BY $50 BY $65 EXAMPLE) $80 NYMEX Oil Three-Way Collar Realization $75 Short-Put at $40/BBL Long-Put at $50/BBL Short-Call at $65/BBL $70 $65 $60 $55 Realize NYMEX plus $10/BBL (difference between long-put and short-put) Realize NYMEX Price Potential Opportunity Loss Realize $65/BBL $50 Realize $50/BBL $45 $40 Potential Gain $35 $30 $30 $35 $40 $45 $50 $55 $60 $65 $70 $75 $80 NYMEX Oil Price ($/BBL) Three-way collars protect downside while providing upside exposure 33

34 PIONEER S YEAR-END 2016 PROVED RESERVES 1 Added 205 MMBOE from the drillbit, or 232% of full-year production, at a drillbit F&D cost of $9.59 per BOE 2 Reflects successful Spraberry/Wolfcamp horizontal drilling program Proved developed F&D cost of $9.11 per BOE 3 Reserve mix 100% U.S. 52% oil / 19% NGLs / 29% gas 93% PD / 7% PUD Year-end 2016 Proved Reserves (MMBOE) Spraberry/Wolfcamp 556 Raton 85 Eagle Ford 45 Other 40 Total 726 Proved Reserves / Production: ~8 years PD Reserves / Production: ~8 years 1) Reflects 2016 SEC pricing (12-month NYMEX average) of $42.82/BBL for oil and $2.48/MMBTU for gas as compared to 2015 SEC pricing of $50.11/BBL for oil and $2.59/MMBTU for gas 2) Excludes negative price revisions (58 MMBOE) and reserves added from acquisitions (4 MMBOE) 3) Added 213 MMBOE of proved developed reserves from (i) discoveries and extensions placed on production during 2016, (ii) transfers from proved undeveloped reserves at year-end 2015 and (iii) technical revisions of previous estimates for proved developed reserves during Revisions of previous estimates excludes price revisions 34

35 PERMIAN BASIN REGIONAL OVERVIEW Tatum Basin Outline of Central Basin Uplift Outline of Central Basin Platform Grisham Fault Big Lake Fault Ozona Uplift Top Woodford structure (from Geomap) Devil s River Uplift Kerr Basin 35

36 MIDLAND BASIN HORIZONTAL RESOURCE POTENTIAL 75 BBOE Recoverable Resource Potential 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) 36

37 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 Horseshoe Atoll Atoka Barnettford Big Lake Fault Calvin Fault 37

38 200 ft MIDLAND BASIN: STACKED PLAY POTENTIAL Midland Basin Clear Fork U. Spraberry M. Spraberry Shale Jo Mill Shale 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 38

39 Million Barrels Oil Per Day PERMIAN BASIN CONTINUES TO GROW Permian Basin is the only continuously growing major U.S. oil shale since downturn began Nov OPEC Decision Permian Basin Eagle Ford Bakken Niobrara Anadarko Other regions in EIA s Drilling Productivity Report Source: EIA, Drilling Productivity Report, October

40 Daily Oil Production (MMBOPD) WTI Price ($/BBL) PERMIAN BASIN HORIZONTALS ARE A GAME CHANGER The Permian Basin has produced >35 BBOE in the past 90 years with an estimated >150 BBOE recoverable resource remaining Permian Basin Tight Oil Production $160 $140 $ $100 Oil Price $ $ Horizontal Drilling Begins - '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 Source: Production data from EIA (U.S. tight oil production selected plays) through September 2017; historical WTI price from EIA $40 $20 $0 40

41 Horizontal Oil Rig Count Peak: 1,115 10/27/17: % vs. bottom U.S. Peak: /27/17: % vs. bottom Permian Bottom: 247 Bottom: 116 Source: Baker Hughes 41

42 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 discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates. Revisions of previous estimates exclude price revisions. 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 reserve additions, on a BOE basis, attributable to discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates divided by annual production of oil, NGLs and gas, on a BOE basis. Revisions of previous estimates exclude price revisions. Proved developed finding and development cost per BOE, or proved developed F&D cost per BOE, means the summation of exploration and development costs incurred (excluding asset retirements obligations) divided by the summation of annual proved reserves, on a BOE basis, attributable to proved developed reserve additions, including (i) discoveries and extensions placed on production during 2016, (ii) transfers from proved undeveloped reserves at year-end 2015 and (iii) technical revisions of previous estimates for proved developed reserves during Revisions of previous estimates exclude price revisions. 42

43 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 presentation, Pioneer includes estimates of quantities of oil and gas using certain terms, such as resource potential, net recoverable resource potential, recoverable resource, estimated ultimate recovery, EUR, oil in place 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