IPAA Oil & Gas Investment Symposium April 10, 2018 Exhibit 99.1A
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 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, cybersecurity risks, ability to implement planned stock repurchases, 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, 2017, 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.
252 MBOEPD Q4 2017 Midland Basin Gross Production By Operator4 (MBOEPD) Permian “pure play” (post divestitures) Largest Midland Basin acreage position with decades of oil drilling inventory ~750,000 gross acres >20,000 drilling locations Low-cost, high-return horizontal wells Low average royalty and acreage cost basis 2018 capital program of $2.9 B (~100% Midland Basin)1 10-year plan2 driven by low-cost, high-return horizontal wells >20% oil production CAGR3 through 2026 >20% cash flow CAGR3 through 2026 15% ROCE4 target in 2026 Cash flow breakeven5 oil price decreasing annually from ~$58/BBL in 2018 to ~$50/BBL in 2020 and ~$40/BBL in 2026 Strong derivatives position protects cash flow Mid-investment grade balance sheet 4) Nov. 2017 DrillingInfo data, gross reported oil and wet gas (unallocated 2-stream) Capital program excludes acquisitions, asset retirement obligations, capitalized interest, G&G G&A and IT system upgrades 10-Year Plan refers to years 2017 through 2026 CAGR - compound annual growth rate Non-GAAP financial measure. Refer to Appendix for definition Refer to Appendix for definition of terms Pioneer at a glance Midland Basin
2018 plan and Capital program Plan to divest Eagle Ford, South Texas, Raton and West Panhandle assets during 2018, making Pioneer a Permian Basin “pure play” Data rooms opened in Q1 After the divestitures are completed, reported revenue per BOE will increase and operating expense per BOE will decrease, thereby significantly improving reported cash operating margins and corporate returns Plan to operate 20 horizontal rigs in the Permian Basin during 2018 16 rigs currently operating in the northern portion of Pioneer’s acreage 2 rigs focused on increasing the DUC inventory to improve operational flexibility Once an adequate DUC inventory is built, the 2 rigs will focus on production growth with incremental production volumes not expected until early 2019 as a result of pad drilling 4 rigs in the southern Wolfcamp JV area; activity will be focused in the northern portion of this area (60% WI) Expecting to POP 250 - 275 wells Reducing 4-string casing design to ~50% of the drilling program from ~75% in 2H 2017 Testing ~45 Version 3.0+ completions in 1H 2018; remaining wells for 2018 currently planned to be predominantly Version 3.0 completions 2018 production forecast reflects this completion mix
2018 plan and capital program (cont.) The 2018 drilling program is expected to deliver Permian Basin oil production growth ranging from 19% to 24% compared to 2017 Total BOE production is forecasted to grow by 19% to 24% compared to 2017 IRRs are expected to average 65% including facilities costs1 2018 capital program of $2.9 B2 Includes $2.65 B for drilling and completions and $260 MM for water infrastructure, vertical integration, field facilities and vehicles Assumes ~5% cost inflation offset by efficiency gains; vertical integration expected to mitigate the impact of 10% to 15% cost inflation forecasted for the industry Program to be funded from forecasted cash flow of $2.8 B1, proceeds from asset divestitures and cash on hand Capital program is expected to be cash flow breakeven3 at an oil price of ~$58 per BBL Oil derivatives cover >85% and gas derivatives cover >60% of forecasted 2018 Permian Basin production Enhancing cash flow with premiums on growing sales to Gulf Coast and export markets Based on $55/BBL oil price and $3/MCF gas price Capital program excludes acquisitions, asset retirement obligations, capitalized interest, G&G G&A and IT system upgrades Refer to Appendix for definition of financial metrics
2018 plan and capital program (cont.) Expect to repay May 2018 debt maturity of $450 MM from cash on hand Net debt to 2018 operating cash flow forecasted to remain below 0.5x Based on Pioneer’s strong balance sheet, expected proceeds from asset divestitures and positive outlook for generating free cash flow1, the Company increased its semiannual per share dividend from $0.04 to $0.16 (equivalent to $0.32 per share on an annualized basis) The Company plans a common stock repurchase program during 2018 to offset the impact of dilution associated with employee stock compensation awards Including return and per-share growth goals in 2018 executive compensation plan Refer to Appendix for definition of financial metrics
NYMEX Oil Price ($/BBL) Capital program excludes acquisitions, asset retirement obligations, capitalized interest, G&G G&A and IT system upgrades Includes vertical integration (pressure pumping and well services equipment, water distribution system and sand mine), field facilities and vehicles Drilling and Completion Capital: $2.65 B $2.63 B Permian Basin (~99% of total) $2.05 B for horizontal drilling program $300 MM for tank batteries/SWDs/below-grade cellars $170 MM for gas processing facilities $110 MM for land/science/other $20 MM Other Assets Other Capital: $260 MM2 Capital program funded from: Cash flow of $2.8 B at $55/BBL oil and $3/MCF gas Proceeds from asset divestitures Cash on hand (including liquid investments) 2018 Capital Program1 and Cash Flow Based on 2018E prices $55/BBL oil and $3/MCF gas 2018 capital program of $2.9 B 2018 Cash Flow Sensitivity to Forward Commodity Prices ($ MM) (Permian Basin) NYMEX Gas Price ($/MCF)
Net debt at the end of Q4 2017 (reflects cash on hand, including liquid investments, of $2.2 B) Unsecured credit facility availability Net debt-to-book capitalization at the end of Q4 1) Excludes issuance costs and issuance discounts of ~$18 MM Maturities and Balances1 Net debt to 2018E operating cash flow of 0.2x Mid-investment grade rated by Moody’s, S&P and Fitch $0.6 B $1.5 B 5% $1.5 B unsecured credit facility (undrawn as of 12/31/17) $600 MM 3.950% 2022 $450 MM 6.875% 2018 $450 MM 7.500% 2020 $250 MM 7.200% 2028 $500 MM 3.450% 2021 $500 MM 4.450% 2026 Liquidity position Expected to be paid with cash on hand in May 2018
Permian Basin production Growth Forecast Permian Basin Net Production >1 MMBOEPD Oil growth: 26% 19% - 24% (Oil growth: 19% - 24%) 2018E 176 – 184 MBOPD 266 – 278 MBOEPD Oil (MBOPD) >700 MBOPD 224 20%+ CAGR (Oil growth: 20%+) 148 118 171 252 - 260 166 - 172 Prolonged freezing temperatures in early January resulted in production losses of ~6 MBOEPD for Q1 (includes impact of shut-in production and frac delays)
Low-Cost, High-Return Permian Basin Horizontal Wells Grow Corporate ROCE2 Annually Decrease Cash Flow Breakeven Oil Price2 Annually Grow Cash Flow Annually; Generate Free Cash Flow2 by 2020 at ~$50 Pioneer’s 10-Year Growth Target >700 MBOPD in 2026 >1 MMBOEPD in 2026 Reflects Pioneer’s average G&A and interest expense on a total Company BOE basis for 2017 Refer to Appendix for definition of financial metrics Pioneer’s 2017 Permian Basin Horizontal Cost Structure ($/BOE) $9.40 $4.46 $1.54 $3.28 ~$19 Proved Developed F&D Production Costs and Taxes G&A1 Interest Expense1 Total Cost Low-cost, High-Return Permian basin horizontal Wells underpin Pioneer’s 10-Year plan
10-Year Plan: significantly Improving Financial metrics1,2,3 >20% CAGR Drilling low-cost, highly productive wells that generate high rates of return as a result of a low all-in cost structure of ~$19 per barrel Drilling program delivers robust cash flow growth that self-funds capital program, improves corporate ROCE and generates free cash flow Based on $55 oil and $3 gas Assumes no improvement in efficiencies or well productivity from YE 2017 Refer to Appendix for definition of financial metrics Return on Capital Employed is a non-GAAP financial measure. Refer to Appendix
Operating 20 horizontal rigs in the Permian Basin Testing ~45 wells in 1H with Version 3.0+ completions Remaining wells for 2018 currently planned to be predominantly Version 3.0 completions Budgeted drilling and completion cost per well: Horizontal production costs per well: $4/BOE to $5/BOE (includes taxes) IRRs averaging 65% assuming Version 3.0 completions and prices of $55/BBL for oil and $3/MCF for gas (includes 2018 tank battery/SWD costs) 2018 Permian Basin Drilling Program Northern Area Southern Wolfcamp JV Area Pioneer’s Acreage Position and 2018 Drilling Areas Interval Lateral Length Gross Well Cost ($MM) Gross EUR (MMBOE) Wolfcamp B ~10,000′ ~$8.9 1.7 Wolfcamp A ~9,500′ ~$8.3 1.4 Spraberry Intervals ~9,500′ ~$7.5 1.1 Plan to place 250-275 horizontal wells on production in 2018 (200 – 225 wells in northern area and ~50 gross wells in JV area) ~60% Wolfcamp B; ~25% Wolfcamp A; ~15% Spraberry Intervals
Hutt Area: Wolfcamp B Updated Early February Updated Early February Updated Early February Updated Early February Cumulative Production (MBOE)1 Early results from 15 version 3.0+ Completions encouraging (Excludes 5 wells that pop’d in December and are still cleaning up) North University Area: LSS South University Area: Wolfcamp B Production normalized for shut-ins Cumulative production normalized to a lateral length of 9,500’ Cumulative Production (MBOE)1 Cumulative Production (MBOE)1 Version 3.0+: 3 wells in Q2 ~9,000′ avg. lateral length 50 bbls/ft and 3,000 lbs/ft Version 3.0+ Version 3.0 Version 3.0+ Version 3.0 Version 2.0: 6 wells since mid-2016 ~10,000′ avg. lateral length Version 3.0+: 3 wells in Q2 ~9,800’ avg. lateral length 67 bbls/ft and 2,500 lbs/ft Version 3.0+ Version 2.0 Version 3.0+: 6 wells since Q2 Q2: 3 wells (7,000’ avg. lateral length)2 Q4: 3 wells (9,700’ avg. lateral length) 67 - 100 bbls/ft and 3,000 - 5,000 lbs/ft Pembrook Area: Wolfcamp B Version 3.0+ Version 3.0 Version 3.0+: 3 wells in Q2 ~9,700′ avg. lateral length 50 bbls/ft and 3,000 lbs/ft Version 3.0: 7 wells since 2016 ~8,300′ avg. lateral length Version 3.0: 26 wells since mid-2016 ~9,500′ avg. lateral length Version 3.0: 24 wells since late-2015 ~8,800′ avg. lateral length Cumulative Production (MBOE)1
13 Jo Mill wells have been POP’d since Q3 2014 2 new wells POP’d during Q4 2017 are showing strong initial results Remaining 11 wells are exhibiting encouraging performance Wells POP’d to date cover a large cross section of Pioneer’s acreage Additional Jo Mill wells planned for 2018 drilling program Jo mill Performance Encouraging Production normalized for shut-ins Jo Mill wells since Q3 2014 Cumulative Production (MBOE)1 Updated Early February 4 POPs during Q2 2017: ~8,250’ avg. lateral length Jo Mill POP Locations Q4 Jo Mill POPs 5 POPs between Q4 2014 and Q1 2017: ~6,800’ avg. lateral length 2 POPs during Q3 2017: ~6,900’ avg. lateral length 2 POPs during Q4 2017: ~7,500’ avg. lateral length
Latest Wolfcamp D well performance impressive Placed first Wolfcamp D well with a Version 3.0 completion on production during Q4 in Midland County 24-hour peak IP rate of 3.6 MBOEPD; 45-day cumulative production of 120 MBOE (72% oil) Strongest 45-day cumulative production for all Pioneer Wolfcamp D wells to date Pioneer has ~450,000 gross acres that are prospective for Wolfcamp D Additional Wolfcamp D wells planned for 2018 drilling program 33 POPs between 2013 and 2015: ~7,900’ avg. lateral length2 Shackelford well ~9,700’ lateral length Q4 Wolfcamp D POP Location Wolfcamp D Wells Version 3.0 Version 1.0 Production normalized for shut-ins Cumulative production normalized to a lateral length of 9,700’ Updated Early February
Unlocking acreage value Plan to appraise first Clearfork horizontal well in Midland County Expect to appraise 10 wells in the Jo Mill and Middle Spraberry intervals with 9 LSS wells Determine optimal development strategy; includes spacing, staggering, sequencing and completion design Plan to appraise 3 Wolfcamp D wells with higher intensity completions Midland Basin Prospective Horizontal Intervals 1 Appraisal in 2018 19 Appraisals in 2018 Full Development Clearfork Middle Spraberry Shale Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Strawn Atoka Barnett Woodford Mississippi Lime Jo Mill Lower Spraberry Shale Full Development 3 Appraisals in 2018 Future Appraisal Future Appraisal 2018 Appraisal Activity
Tank Battery/Saltwater Disposal (SWD) Facilities/Below-Grade Cellars Expect to spend ~$300 MM in 2018 for new facilities and expansions ~65% of the ultimate field-wide tank battery/SWD requirements expected to be completed as of year-end 2018 Utilizing below-grade cellars for 24-well pads minimizes future surface acreage requirements and thereby reduces full-cycle surface costs per well Gas Processing 2018 spending expected to be ~$170 MM Includes capital for 2 new plants in 2018 (200 MMCFPD each, first in Q1 and second in Q3) and 2 additional plants in 2019 (250 MMCFPD each, first in Q1 and second in Q3) Also includes capital for gathering system compression and new connections Expect to need 1 to 2 new plants per year post-2019 as industry gas volumes grow Water Distribution System 2018 spending expected to be ~$135 MM for Midland wastewater treatment plant upgrade and additional subsystems, frac ponds and produced water reuse Sand Supply Initial contract signed for West Texas sand purchases with first offtake scheduled for April Additional contracts being negotiated Expansion of Brady sand mine deferred as a result of West Texas sand purchases Continuing to build out Permian basin infrastructure and vertical Integration Tank Battery/SWD Gas Processing Plant Water Distribution Below-Grade Cellar
increasing oil takeaway to the gulf coast and export capability provides LLS and brent-related pricing Exported ~90 MBOPD barrels of Permian Basin oil production during Q4 Expect to export ~90 MBOPD in Q1 2018 Export capacity in 1H 2018 is ~110 MBOPD, increasing to ~150 MBOPD in 2H 2018 Currently delivering >160 MBOPD of Permian Basin oil to the Gulf Coast under firm pipeline contracts Longer-term target is to maintain 70% - 80% of forecasted net oil production under firm pipeline transport to the Gulf Coast for domestic refinery sales and exports ~55 ~60 ~80 ~115 Sales Volumes to Gulf Coast (MBOPD)1 Exports Permian Express Houston Magellan BridgeTex Cactus Midland Corpus Christi Nederland 15 89 12 12 Q1 2017 through Q3 2017 exclude exports from Corpus Christi Gulf Coast Sales
PXD Investment Highlights Pioneer will be a Permian Basin “pure play” with ~750,000 gross acres in the Midland Basin (post divestitures) High oil exposure from substantial resource potential in the Midland Basin: >20,000 drilling locations Expect to deliver compound annual oil production growth of >20% through 2026 while maintaining a strong balance sheet Drilling program delivers robust cash flow growth that self-funds capital program, improves corporate ROCE and generates free cash flow during the 10-Year Plan Strong derivatives position protects cash flow Mid-investment grade balance sheet provides financial flexibility
Appendix slides
Production by Commodity
$(0.34) Production & Ad Valorem Taxes Workovers LOE Third-Party Transportation Natural Gas Processing Q2 ′17 Q4 ′17 Q4 ′16 Q1 ′17 ($0.16) Q3 ′17 ($0.28) $7.60 $8.20 $8.42 $8.38 ($0.18) $8.11 ($0.29) Production Costs (per BOE) Q4 2017 compared to Q3 2017: LOE declined due to increasing production attributable to lower cost horizontal Permian Basin wells and cost reduction initiatives Reduced Permian Basin vertical well workovers in Q4
Cash Margins By Asset Permian Horizontals Permian Verticals Eagle Ford Other Assets Total Company Realized price (ex-hedges) $ 41.27 $ 39.81 $ 31.86 $ 23.46 $ 38.68 Production costs (1.87) (16.02) (10.75) (10.95) (5.37) Production and ad valorem taxes (2.53) (2.25) (1.12) (1.00) (2.23) Cash margin $ 36.87 $ 21.54 $ 19.99 $ 11.51 $ 31.08 % Oil 67% 62% 37% 14% 59% Q4 2017 Cash Margin by Asset ($ per BOE) 1 Includes lease operating expense, third-party transportation, workover expense and net natural gas processing cost
Pioneer’s Year-End 2017 Proved Reserves1 Reflects 2017 SEC pricing (12-month NYMEX average) of $51.34/BBL for oil and $2.98/MMBTU for gas as compared to 2016 SEC pricing of $42.82/BBL for oil and $2.48/MMBTU for gas Excludes positive price revisions (52 MMBOE), proved reserves divested (7 MMBOE) and proved reserves acquired (1 MMBOE) Added 266 MMBOE of proved developed reserves from (i) discoveries and extensions placed on production during 2017, (ii) transfers from proved undeveloped reserves at year-end 2016 and (iii) technical revisions of previous estimates for proved developed reserves during 2017. Revisions of previous estimates excludes price revisions Added 314 MMBOE from the drillbit, or 309% of full-year production, at a drillbit F&D cost of $8.46 per BOE2 Reflects successful Permian Basin and Eagle Ford horizontal drilling program Permian Basin (including both horizontal and vertical activity) proved developed F&D cost of $9.51 per BOE3 Reserve mix Total Company: 100% U.S. 49% oil / 21% NGLs / 30% gas 92% PD / 8% PUD Permian Basin Only: 59% oil / 22% NGLs / 19% gas 93% PD / 7% PUD Proved Reserves / Production: ~10 years PD Reserves / Production: ~9 years Year-End 2017 Proved Reserves (MMBOE) Permian Basin 763 Raton 96 Eagle Ford 80 Other 46 Total 985
Continue to use derivatives to mitigate commodity price exposure in order to support funding for development programs and to maintain strong financial position Continue to use a variety of derivative instruments, but focus will be on mitigating downside risk while providing upside exposure; primary derivative instruments will be: Swaps Collars with short puts (three-way collars) Enter derivative agreements only with counterparties that are “A” rated or better Actively monitor credit exposure to each counterparty and counterparty credit trends No margin requirements with counterparties Derivative philosophy
Permian Basin Oil Coverage: >85% in 2018 and >30% in 2019 Oil Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019 Collars (BPD) 3,000 3,000 3,000 3,000 - NYMEX Short Call Price ($/BBL) $58.05 $58.05 $58.05 $58.05 $ - NYMEX Put Price ($/BBL) $45.00 $45.00 $45.00 $45.00 $ - Three Way Collars (BPD)1 149,000 149,000 154,000 159,000 65,000 NYMEX Call Price ($/BBL) $57.79 $57.79 $57.70 $57.62 $60.74 NYMEX Put Price ($/BBL) $47.42 $47.42 $47.34 $47.26 $52.69 NYMEX Short Put Price ($/BBL) $39.38 $37.38 $37.31 $37.23 $42.69 When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price Open Commodity Derivative Positions as of 2/5/18
Represent basis swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices. The basis swaps fix the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus the price differential on 6,920 MMBtu per day, which is equivalent to 2,500 Bbls per day of ethane Open Commodity Derivative Positions as of 2/5/18 Ethane Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019 Frac Spread (BPD) 1 2,500 2,500 2,500 2,500 2,500 MMBTUPD Equivalent 6,920 6,920 6,920 6,920 6,920 Price differential to NYMEX ($/MMBTU) $1.60 $1.60 $1.60 $1.60 $1.60 Permian Basin NGL Coverage: <5% in 2018 and 2019
Permian Basin Gas Coverage: >60% in 2018 Gas Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019 Swaps (MMBTUPD) 1 61,111 100,000 100,000 100,000 - NYMEX Price ($/MMBTU) $3.41 $3.00 $3.00 $3.00 $ - Three Way Collars (MMBTUPD)1,2 100,000 50,000 50,000 50,000 - NYMEX Call Price ($/MMBTU) $3.82 $3.40 $3.40 $3.40 $ - NYMEX Put Price ($/MMBTU) $3.15 $2.75 $2.75 $2.75 $ - NYMEX Short Put Price ($/MMBTU) $2.57 $2.25 $2.25 $2.25 $ - 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 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 Represents basis swaps contracts that fix the basis differential between Permian Basin and Southern California or Houston Ship Channel index prices for Permian Basin gas forecasted for sale in Southern California or the Gulf Coast region Permian Basin Gas Basis Swaps Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019 Southern California (MMBTUPD)3 80,000 40,000 80,000 66,522 84,932 Price Differential to NYMEX ($/MMBTU) $0.34 $0.30 $0.30 $0.50 $0.33 Houston Ship Channel (MMBTUPD) 3 6,556 - - - - Price Differential to NYMEX ($/MMBTU) $0.72 $ - $ - $ - $ - Open Commodity Derivative Positions as of 2/5/18
Three-Way Collars ($40 by $50 by $65 Example) Short-Put at $40/BBL Long-Put at $50/BBL Short-Call at $65/BBL Potential Gain Realize NYMEX plus $10/BBL (difference between long-put and short-put) Realize $50/BBL Realize NYMEX Price Realize $65/BBL Potential Opportunity Loss Three-way collars mitigate downside risk while providing upside exposure
Midland Basin Midstream Infrastructure Gas Processing Targa System PXD has 27% interest Current capacity: 855 MMCFPD1 PXD production makes up ~40% of throughput Joyce Plant expected to be online in Q1 2018 (200 MMCFPD) and Johnson Plant in Q3 2018 (200 MMCFPD) 2 additional plants expected to be online in Q1 and Q3 of 2019 (250 MMCFPD) WTG (Martin County and Sale Ranch plants) PXD has 30% interest Current capacity: 320 MMCFPD2 PXD production makes up ~20% of throughput Pipeline NGL Takeaway to Mont Belvieu 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 Lone Star Pipeline (Energy Transfer) To Mont Belvieu Benedum Edward Joyce Sale Ranch / Martin County West Texas Pipeline To Mont Belvieu Chaparral Pipeline To Mont Belvieu Midkiff Driver Johnson Buffalo PXD Acreage Existing NGL Pipeline
Innovation Will be A Key contributor To achieving Pioneer’s 10-year Vision New technology initiatives are focused on improving productivity 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) Large-scale produced water recycling Partnering with national labs and service companies 4-D fracture propagation modeling Fluid end metallurgy Dynamic drill string modeling
Benefits of water reuse vs. disposal Pioneer’s water infrastructure provides a unique opportunity to reuse produced water Benefits of reusing produced water include: 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 to 15% - 20% of total fracture stimulation requirements by YE 2018 Tank Battery Existing Storage Pond Produced Water Treatment & Blending Water for Completion Water Reuse Produced Water SWD Facility Tank Battery Water Disposal Water Disposal
Casing Design Comparison 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 higher-pressured 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 Water Disposal Zone (Higher Pressures) Clearfork - Spraberry (Lower Pressures) 3-String 4-String 13 3/8’’ Surface Casing 9 5/8’’ Intermediate Casing 7 5/8’’ Casing 5 1/2’’ Production Casing 13 3/8’’ Surface Casing 9 5/8’’ Intermediate Casing 5 1/2’’ Production Casing
Permian Basin Takes Global Stage “U.S. now holds more oil reserves than Saudi Arabia” – Rystad Energy, July 4, 2016 1) Total recoverable resource includes oil and gas for all fields Source: Wood Mackenzie for international fields; Permian Basin from internal estimates Produced To Date Midland Basin Delaware Basin “The Midland and Delaware basins hold the largest number of undrilled, low-cost tight oil locations in the Lower 48. No other region comes close.” – Wood Mackenzie
Permian Basin regional overview Tatum Basin Delaware Basin Midland Basin Eastern Shelf Northwest Shelf Central Basin Uplift Ozona Uplift Diablo Uplift Puckett- Grey Ranch Uplift Val Verde Basin Devil’s River Uplift Kerr Basin Big Lake Fault Grisham Fault Outline of Central Basin Uplift Outline of Central Basin Platform Marathon Thrust Belt Ft. Stockton High Elsinore Uplift Top Woodford structure (from Geomap)
Midland Basin: Stacked Play Potential “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 200 ft Eagle Ford Condensate Barnett Combo Marcellus Barnett Miss Lime Woodford Wolfcamp D Wolfcamp A Wolfcamp B L. Spraberry Shale M. Spraberry Shale Clear Fork Bakken Jo Mill Shale Midland Basin Source: PXD Dean Wolfcamp C U. Spraberry Atoka Strawn Niobrara
Regional Cross Section D-D’ Spraberry Spraberry WC B,C1 WC-D LSS LSS Strawn Miss Woodford Woodford WC-D Horseshoe Atoll South North WC-A WC-A WC-Upper B WC-C Ozona Platform Atoka Jo Mill Shale Jo Mill Shale 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 D D’ Big Lake Fault Calvin Fault Barnettford WC-Lower B Miss Woodford Clear Fork MSS MSS
Impact of Horizontal Technology in the Midland Basin From 2009 to 2012, production growth primarily attributable to increased vertical activity Post 2012, production growth driven by horizontal activity Midland Basin production has increased ~1,300,000 BOEPD since 2009 Source: IHS Energy monthly data through November 2017 for the Spraberry, Credo East, Garden City South and Lin Fields; 2-stream production data Midland Basin Production
Permian Basin Horizontals Are A Game Changer Source: Production data from EIA (U.S. tight oil production – selected plays) through December 2017; historical WTI price from EIA The Permian Basin has produced >35 BBOE in the past 90 years with an estimated >150 BBOE recoverable resource remaining Oil Price Permian Basin Tight Oil Production Horizontal Drilling Begins
Permian Basin continues to grow Eagle Ford Bakken Permian Basin Source: EIA, Drilling Productivity Report, January 2018 Permian Basin is the only continuously growing major U.S. oil shale since downturn began Niobrara Nov. 2014 OPEC Decision Other regions in EIA’s Drilling Productivity Report Anadarko
Oil Breakevens by Shale play in north America Source: Citi Research Report (9/13/2017) – Breakeven oil price assumes $3/MMBtu flat gas price Midland Basin considered the top oil shale play in North America with a breakeven oil price of ~$24/BBL
Horizontal Oil Rig Count Previous Peak: 349 Bottom: 116 1/26/18: 385 +232%↑ vs. bottom Peak: 1,115 Bottom: 247 1/26/18: 662 +168%↑ vs. bottom U.S. Permian Source: Baker Hughes The Permian Basin is operating more horizontal oil rigs than ever before
“Return on Capital Employed” (ROCE) equals net income adjusted for tax-effected interest expense, net noncash MTM derivative gains and losses and other unusual items1 divided by the summation of average equity plus average net debt “Free Cash Flow” (FCF) occurs when net cash provided by operations (before working capital changes) exceeds Capital Expenditures “Cash Flow Breakeven Oil Price” is the NYMEX WTI price at which net cash flow provided by operations (before working capital changes) equals Capital Expenditures “Capital Expenditures” equal the Company’s planned capital budget for any year excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and IT system upgrades This presentation also contains a forward-looking non-GAAP financial measure, return on capital employed. Due to its forward-looking nature, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measure, such as future noncash property impairments, gains or losses on future divestitures and future noncash MTM derivative gains and losses. Accordingly, Pioneer is unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measure to its most directly comparable forward-looking GAAP financial measure. Amounts excluded from this non-GAAP measure in future periods could be significant. Supplemental information Unusual items have historically included noncash property impairments, gain/loss on asset divestitures and tax-related items
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, extensions 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, extensions 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 retirement 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 2017, (ii) transfers from proved undeveloped reserves at year-end 2016 and (iii) technical revisions of previous estimates for proved developed reserves during 2017. Revisions of previous estimates exclude price revisions. Reserves Audit, F&D Costs and Reserve Replacement
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,” “recoverable resource,” “net recoverable resource potential,” “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 www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
Common share repurchases The stock purchase program allows for up to $100 million of stock to be repurchased during 2018. Pioneer may repurchase shares from time to time at management’s discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. In addition, shares may also be purchased pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, which would permit shares to be repurchased when the Company might otherwise be precluded from doing so under insider trading laws. The amount and timing of repurchases are subject to a number of factors, including stock price, trading volume and general market conditions, and the program may be modified, suspended or terminated at any time by Pioneer’s Board of Directors. The Company intends to fund repurchases under the program from cash flow, proceeds from asset divestitures or cash and cash equivalents.