J P M o r g a n E n e r g y C o n f e r e n c e J U N E 1 9, 2018

Transcription

1 J P M o r g a n E n e r g y C o n f e r e n c e J U N E 1 9, 2018

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, 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 Supplemental Slides included in this presentation for other important information. 2

3 PIONEER AT A GLANCE Permian pure play (post divestitures) Largest Midland Basin acreage position with Midland Basin decades of oil drilling inventory ~750,000 gross acres >20,000 drilling locations Low-cost, high-return horizontal wells Oil 65% 260 MBOEPD Q NGL 21% Gas 14% Low average royalty and acreage cost basis 10-year plan 1 driven by low-cost, high-return horizontal wells >20% oil production CAGR 2 through Midland Basin Gross Production By Operator 5 (MBOEPD) >20% cash flow CAGR 2 through % ROCE 3 target in Cash flow breakeven 4 oil price ~$40/BBL in 2026 Mid-investment grade balance sheet 1) 10-Year Plan refers to years 2017 through ) CAGR - compound annual growth rate 3) Non-GAAP financial measure. Refer to Supplemental Slides for definition 4) Refer to Supplemental Slides for definition of terms 5) Feb 2018 DrillingInfo data, gross reported oil and wet gas (unallocated 2-stream) 3

4 2018 UPDATE Continuing to operate 20 horizontal rigs in the Permian Basin Expecting to POP wells during 2018 Drilling the most productive, high-return wells in the Basin Cash operating margins and IRRs continue to be strong Evaluating the timing of rig additions later in 2018 to support 2019 plan On track to place ~45 Version 3.0+ completions on line during 1H 2018 as planned Version 3.0+ completions to date continue to significantly outperform Version 3.0 o Completed 31 Version 3.0+ wells in Q1; placed 16 Version 3.0+ wells on production Evaluating the number of Version 3.0+ completions to be added in 2H 2018 Planning to appraise 3 additional Wolfcamp D wells with Version 3.0 completions during 2018 First Wolfcamp D well with this type of completion (placed on production during Q4 2017) has delivered 130-day cumulative production of 260 MBOE (72% oil) Expect to appraise 19 wells in the Middle Spraberry Shale, Jo Mill and Lower Spraberry Shale in 2018 to determine the optimal long-term development strategy 4

5 NYMEX Gas Price ($/MCF) 2018 UPDATE (CONT.) 2018 capital spending to be funded from forecasted cash flow of ~$3.2 B (assumes oil price of $66/BBL and gas price of $2.80/MCF for the remainder of the year) 2018 capital budget of $2.9 B expected to be increased due to additional Version 3.0+ completions, late-year rig additions preparing for 2019 and inflation 2018 Permian production growth continues to be forecasted at 19% - 24%; trending toward the upper half of the range Q2 production impacted by high field line pressures and downtime due to severe weather Version 3.0+ wells exhibit longer clean up times; continue 2018 Cash Flow Sensitivity to Forward Commodity Prices ($ MM) (Permian Basin) to significantly outperform Version 3.0 wells Repaid May debt maturity of $450 MM from cash on hand Repurchased ~$17 MM of common stock in Q1 under the Company s $100 MM authorized program 1 NYMEX Oil Price ($/BBL) Based on assumed prices for remainder of the year of $66/BBL oil & $2.80/MCF gas 1) See Supplemental Slides for details on the repurchase program 5

6 2018 UPDATE (CONT.) Progressing divestiture process for Eagle Ford Shale, South Texas and West Panhandle assets, making Pioneer a Permian pure play Signed a purchase and sale agreement to sell Raton Basin assets for $79 million; closing expected by end of July Closed sale of 10,200 net acres in the Eagle Ford Shale for $103 MM After all of the divestitures are completed, reported cash operating margins and corporate returns will be significantly improved 1) Non-GAAP financial measure. Refer to Supplemental Slides for definition 6

7 36 VERSION 3.0+ COMPLETIONS SHOWING STRONG RESULTS Northern Midland Basin: LSS Cumulative Production (MBOE) Version 3.0+: 3 wells ~9,000 avg. lateral length Days on Production Southern Upton and Reagan: Wolfcamp B Cumulative Production (MBOE) 1 Version 3.0+: 5 wells ~10,000 avg. lateral length Updated Late April Version 3.0: 27 wells since late-2015 ~8,700 avg. lateral length Days on Production 1) Production normalized for shut-ins 2) Cumulative production normalized to a lateral length of 9,700 Updated Late April Version 2.0: 7 wells since late-2015 ~9,600 avg. lateral length Central Midland Basin: Wolfcamp B Cumulative Production (MBOE) Version 3.0+: 12 wells ~9,700 avg. lateral length Version 3.0: 16 wells since 2016 ~9,200 avg. lateral length Updated Late April Days on Production Pembrook and Giddings: Wolfcamp B Cumulative Production (MBOE) 1 Version 3.0+: 16 wells ~8,300 avg. lateral length 2 Updated Late April Version 3.0: 30 wells since mid-2016 ~9,700 avg. lateral length Days on Production 7

8 PERMIAN BASIN PRODUCTION GROWTH FORECAST Permian Basin Net Production MBOPD MBOEPD >1 MMBOEPD >700 MBOPD Oil (MBOPD) Q1 Q2 Q3 Q4 2026E 2018E 8

9 FIRM TRANSPORTATION TO THE GULF COAST INSULATES PIONEER FROM MIDLAND BASIS DIFFERENTIAL Sales Volumes to Gulf Coast (MBOPD) 1 ~160 Midland Houston Corpus Christi Nederland ~115 ~80 ~55 ~ Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Gulf Coast Refinery Sales Exports Currently delivering ~160 MBOPD of Permian Basin net oil production to the Gulf Coast under firm transportation contracts; represents ~95% of Pioneer s current Permian production Brent-related pricing premiums received on Gulf Coast refinery and export sales added $16 MM of incremental cash flow in Q1 Exported 87 MBOPD during Q1; similar volume anticipated in Q2 Expect exports to grow during 2H as Pioneer increases its export capacity from ~110 MBOPD to ~150 MBOPD Targeting >90% of long-term Permian Basin net oil production under firm pipeline transportation to the Gulf Coast for refinery sales and exports Volumes under firm transportation contracts increases through 2021 commensurate with forecasted production growth 1) Q through Q exclude exports from Corpus Christi 9

10 WELL POSITIONED TO MOVE PERMIAN GAS PRODUCTION SoCal Waha Midland Gulf Coast Express Pipeline Agua Dulce Exports to Mexico Refining & Petchem Markets LNG Exports ~75% of Pioneer s Q1 Permian Basin net gas production of 216 MMCFPD is sold under firm pipeline contracts to the southern California market Uplift of $0.60 per MCF Remainder sold primarily at Waha under term contracts Secured firm transport on Kinder Morgan s Gulf Coast Express Pipeline Access to LNG exports, refineries, petrochemical facilities and Mexican markets Expected to be on line at the end of Q Firm transportation and term contracts provide flow assurance for gas <5% of estimated 2018 total Permian oil, NGL and gas revenue derived from gas 10

11 Breakeven Oil Price ($/BBL) OIL BREAKEVENS BY SHALE PLAY IN THE U.S. $60 $50 $40 $30 $20 $10 $ - Permian Basin considered among the top oil shale plays in North America with a breakeven oil price of less than $30/BBL Source: Citi Research Report (4/11/2018) Breakeven oil price assumes $3/MMBtu flat gas price 11

12 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 drives industry leading breakeven oil price Source: Citi Research Report (4/11/2018) 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 12

13 LOW-COST, HIGH-RETURN PERMIAN BASIN HORIZONTAL WELLS UNDERPIN PIONEER S 10 -YEAR PLAN Pioneer s 2017 Permian Basin Horizontal Cost Structure ($/BOE) Low-Cost, High-Return Permian Basin Horizontal Wells $1.54 $3.28 ~$19 $9.40 $4.46 Grow Corporate ROCE 2 Annually Grow Cash Flow Annually and Generate Free Cash Flow 2 Decrease Cash Flow Breakeven Oil Price 2 Annually Proved Developed F&D Production Costs and Taxes G&A 1 Interest Expense 1 Total Cost Pioneer s 10-Year Growth Target >700 MBOPD in 2026 >1 MMBOEPD in ) Reflects Pioneer s average G&A and interest expense on a total Company BOE basis for ) Refer to Definitions slide in Supplemental Slides for definition of financial metrics 13

14 PIONEER S TEMPLATE FOR ENHANCING SHAREHOLDER VALUE FOCUS ON RETURNS: Low-cost, high-return Permian wells underpin increasing corporate returns CAPITAL DISCIPLINE: Capital program within cash flow drives strong production growth RETURN OF CAPITAL: Increasing free cash flow 1 generation leads to return of capital to shareholders PRESERVE STRONG BALANCE SHEET: Maintain low leverage ratios to provide financial flexibility HIGHLY REPEATABLE PROGRAM: Decades of low-risk drilling inventory with cash flow breakeven oil prices 1 that decrease annually Permian Basin drilling provides high return on capital and leads to increasing return of capital 1) See Supplemental Slides for definition of financial metrics 14

15 SUPPLEMENTAL SLIDES 15

16 LIQUIDITY POSITION Net debt at the end of Q (reflects cash on hand, including liquid investments, of $1.8 B) Unsecured credit facility availability Net debt-to-book capitalization at the end of Q1 $0.9 B $1.5 B 7% Maturities and Balances $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 3/31/18) Repaid May debt maturity of $450 MM from cash on hand Net debt to 2018E operating cash flow of 0.3x Mid-investment grade rated by Moody s, S&P and Fitch 1) Excludes issuance costs and issuance discounts of ~$16 MM 16

17 PRODUCTION BY COMMODITY Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Midland Basin Oil (BOPD) 104, , , , ,628 Horizontal NGL (BOEPD) 26,709 32,546 37,923 40,895 45,718 Gas (MCFPD) 128, , , , ,987 Total (BOEPD) 152, , , , ,343 Midland Basin Oil (BOPD) 29,819 27,279 25,490 25,816 25,192 Vertical NGL (BOEPD) 9,820 9,630 9,755 8,933 8,678 Gas (MCFPD) 50,456 48,453 39,266 39,034 35,999 Total (BOEPD) 48,048 44,984 41,789 41,255 39,871 Total Midland Basin Oil (BOPD) 134, , , , ,820 NGL (BOEPD) 36,529 42,176 47,678 49,828 54,396 Gas (MCFPD) 178, , , , ,986 Total (BOEPD) 200, , , , ,214 Assets Being Divested Oil (BOPD) 11,097 9,577 9,373 13,661 12,699 NGL (BOEPD) 10,299 11,092 9,668 12,567 11,785 Gas (MCFPD) 160, , , , ,883 Total (BOEPD) 48,066 46,519 44,347 53,477 51,631 Total Operations Oil (BOPD) 145, , , , ,519 NGL (BOEPD) 46,829 53,267 57,346 62,396 66,181 Gas (MCFPD) 338, , , , ,869 Total (BOEPD) 248, , , , ,845 17

18 PRODUCTION BY COMMODITY (ASSETS BEING DIVESTED) Q1 '17 Q2 '17 Q3 '17 Q4 '17 Q1 '18 Eagle Ford Oil (BOPD) 7,870 6,279 6,956 9,896 9,010 NGL (BOEPD) 6,800 6,490 6,981 8,280 8,178 Gas (MCFPD) 45,069 39,531 40,775 50,755 48,849 Total (BOEPD) 22,182 19,359 20,734 26,634 25,331 Raton Oil (BOPD) NGL (BOEPD) Gas (MCFPD) 89,959 89,228 88,490 86,352 83,505 Total (BOEPD) 14,993 14,871 14,748 14,392 13,917 West Panhandle Oil (BOPD) 1,997 2,061 1,181 1,449 1,368 NGL (BOEPD) 3,344 4,371 2,466 3,786 3,091 Gas (MCFPD) 5,390 7,936 5,266 11,302 11,324 Total (BOEPD) 6,240 7,755 4,525 7,119 6,346 South Texas Oil (BOPD) 1,226 1,230 1,235 2,306 2,312 NGL (BOEPD) Gas (MCFPD) 19,565 18,346 17,225 15,039 19,155 Total (BOEPD) 4,641 4,517 4,325 5,313 6,019 Other Oil (BOPD) NGL (BOEPD) Gas (MCFPD) Total (BOEPD) Assets Being Divested Oil (BOPD) 11,097 9,577 9,373 13,661 12,699 NGL (BOEPD) 10,299 11,092 9,668 12,567 11,785 Gas (MCFPD) 160, , , , ,883 Total (BOEPD) 48,066 46,519 44,347 53,477 51,631 18

19 NEW REVENUE RECOGNITION STANDARD The Company adopted the new revenue recognition standard (Accounting Standards Update No , (ASC 606) Revenue from Contracts with Customers ) effective January 1, 2018 Under the new rule, gas processing fees and associated downstream fractionation and transportation fees that were previously reflected as a reduction in the Company s reported NGL and gas revenues are now required to be recognized as an expense in the Company s production costs As a result of this change, reported NGL and gas revenues and associated price realizations will be higher, with an equivalent offsetting increase in production costs Adoption of this new rule results in no change to the Company s cash operating margins Q Accounting Change Reconciliation Reporting Prior to Accounting Change New Reporting Basis (as of Q1 2018) Effect of Change $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated Oil and Gas Sales Oil sales $ 1,013 $ per Bbl $ 1,013 $ per Bbl $ - $ - per Bbl NGL sales per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf Oil and gas sales $ 1,223 $ $ 1,266 $ $ 43 $ 1.53 Production Costs $ 170 $ 6.07 $ 213 $ 7.60 $ 43 $ 1.53 Production Taxes $ 2.70 $ 2.70 $ - Q1 Cash Margin $ $ $ - New accounting rule is cash operating margin neutral 19

20 2017 EFFECT OF NEW REVENUE RECOGNITION STANDARD The adoption of ASC 606 was effective January 1, 2018, this chart illustrates the pro forma effect of the accounting change as if ASC 606 had been effective for Q Q Q Q $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated $ MM per BOE except as indicated Reporting Prior to Accounting Change: Oil sales $ 643 $ per Bbl $ 602 $ per Bbl $ 674 $ per Bbl $ 873 $ per Bbl NGL sales per Bbl per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf per Mcf Oil and Gas Sales $ 809 $ $ 768 $ $ 855 $ $ 1,085 $ Production Costs Production Taxes Cash Margin $ 621 $ $ 570 $ $ 650 $ $ 872 $ Pro Forma impact of Accounting Change: Oil sales $ 643 $ per Bbl $ 602 $ per Bbl $ 675 $ per Bbl $ 874 $ per Bbl NGL sales per Bbl per Bbl per Bbl per Bbl Gas sales per Mcf per Mcf per Mcf per Mcf Oil and Gas Sales $ 838 $ $ 799 $ $ 894 $ $ 1,128 $ Production Costs Production Taxes Cash Margin $ 621 $ $ 570 $ $ 650 $ $ 872 $ New accounting rule is cash operating margin neutral 20

21 PRODUCTION COSTS 1 (PER BOE) Workovers Production & Ad Valorem Taxes Gathering, Processing & Transportation LOE $10.30 $9.69 $9.70 $9.63 $9.09 $0.82 $0.59 $0.76 $1.02 $0.78 $2.11 $2.19 $2.70 $2.10 $2.23 $2.28 $2.13 $2.32 $2.47 $2.29 $4.99 $4.79 $4.48 $4.14 $4.41 Q compared to Q4 2017: Increase in LOE primarily driven by labor costs, fuel and hot oil rates Production taxes higher due to increase in oil prices Natural Gas Processing ($0.28) ($0.18) ($0.29) $(0.34) $(0.10) Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 1) Prior period production costs have been adjusted pro forma for adoption of ASC 606. This is a non-gaap financial measure. See reconciliation in Supplemental Slides 21

22 CASH MARGINS BY ASSET Q Cash Margin by Asset ($ per BOE) Permian Horizontals Permian Verticals Eagle Ford Other Assets Total Company Realized price (ex-derivatives) 1 $ $ $ $ $ ,2 Production costs (4.18) (19.93) (12.18) (13.05) (7.60) Production and ad valorem taxes (2.95) (2.97) (1.63) (1.27) (2.70) Cash margin $ $ $ $ 9.66 $ % Oil 66% 63% 36% 14% 59% 1) Reflects adoption of new revenue recognition rule; see New Revenue Recognition Standard slide for a description of the impact of adopting the new rule 2) Includes lease operating expense, gathering, processing and transportation, workover expense and net natural gas processing cost 22

23 10-YEAR PLAN: SIGNIFICANTLY IMPROVING FINANCIAL METRICS 1,2,3 Cash Flow ($B) >$11 ~$58 4 Cash Flow Breakeven Oil Price ~$50 ~$40 ~$ Return on Capital Employed 5 15% 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 5% 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 with no derivatives beginning in ) Assumes no improvement in efficiencies or well productivity from YE ) Refer to Definitions slide in Supplemental Slides for definition of financial metrics 4) Assumes capital spending of $2.9 B 5) Return on Capital Employed is a non-gaap financial measure. Refer to Supplemental Slides 23

24 PIONEER S YEAR-END 2017 PROVED RESERVES 1 Added 314 MMBOE from the drillbit, or 309% of full-year production, at a drillbit F&D cost of $8.46 per BOE 2 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 BOE 3 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 1) 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 2) Excludes positive price revisions (52 MMBOE), proved reserves divested (7 MMBOE) and proved reserves acquired (1 MMBOE) 3) 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 Revisions of previous estimates excludes price revisions 24

25 CONTINUING TO BUILD OUT PERMIAN BASIN INFRASTRUCTURE AND VERTICAL INTEGRATION 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 o Includes capital for 2 new plants in 2018 (200 MMCFPD each, one completed in Q1 and the second to be completed in Q3) and 2 additional plants in 2019 (250 MMCFPD each, first in Q1 and second in Q2) o 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 executed in April o Additional contracts being negotiated Expansion of Brady sand mine deferred as a result of West Texas sand purchases Tank Battery/SWD Below-Grade Cellar Gas Processing Plant Water Distribution 25

26 DERIVATIVE PHILOSOPHY 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 26

27 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 mitigate downside risk while providing upside exposure 27

28 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Oil Q Q Q Collars (BPD) 3,000 3,000 3,000 - NYMEX Short Call Price ($/BBL) $58.05 $58.05 $58.05 $ - NYMEX Put Price ($/BBL) $45.00 $45.00 $45.00 $ - Three Way Collars (BPD) 1 149, , ,000 65,000 NYMEX Call Price ($/BBL) $57.79 $57.70 $57.62 $60.74 NYMEX Put Price ($/BBL) $47.42 $47.34 $47.26 $52.69 NYMEX Short Put Price ($/BBL) $37.38 $37.31 $37.23 $42.69 Permian Basin Oil Coverage: >85% in 2018 and >30% 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 28

29 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Ethane Q Q Q Frac Spread (BPD) 1 2,500 2,500 2,500 2,500 MMBTUPD Equivalent 6,920 6,920 6,920 6,920 Price differential to NYMEX ($/MMBTU) $1.60 $1.60 $1.60 $1.60 Permian Basin NGL Coverage: <5% in 2018 and )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 29

30 OPEN COMMODITY DERIVATIVE POSITIONS AS OF 5/1/18 Gas Q Q Q Swaps (MMBTUPD) 1 100, , ,000 - NYMEX Price ($/MMBTU) $3.00 $3.00 $3.00 $ - Three Way Collars (MMBTUPD) 1,2 50,000 50,000 50,000 - NYMEX Call Price ($/MMBTU) $3.40 $3.40 $3.40 $ - NYMEX Put Price ($/MMBTU) $2.75 $2.75 $2.75 $ - NYMEX Short Put Price ($/MMBTU) $2.25 $2.25 $2.25 $ - Permian Basin Gas Basis Swaps Q Q Q Southern California (MMBTUPD) 3 40,000 80,000 66,522 84,932 Price Differential to NYMEX ($/MMBTU) $0.30 $0.30 $0.50 $0.33 Permian Basin (MMBTUPD) 4-50,000 50,000 37,397 Price Differential to NYMEX ($/MMBTU) $ - $ (1.50) $ (1.50) $ (1.50) Permian Basin Gas Coverage: >60% 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, 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 3)The referenced basis swap contracts fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California 4)The referenced basis swap contracts fix the basis differentials between the index price at which the Company sells a portion of its Permian Basin gas and the NYMEX index price used in swap contracts and collar contracts with short puts 30

31 MIDLAND BASIN MIDSTREAM INFRASTRUCTURE Gas Processing Targa System PXD has 27% interest Current capacity: 1,055 MMCFPD 1 PXD production makes up ~40% of throughput Buffalo Sale Ranch / Martin County Pipeline NGL Takeaway to Mont Belvieu Chaparral & West Texas Pipelines PXD production throughput of ~13 MBPD Joyce Plant online in Q (200 MMCFPD) and Johnson Plant in Q (200 MMCFPD) 2 additional plants expected to be online in Q1 and Q2 of 2019 (250 MMCFPD) WTG (Martin County and Sale Ranch plants) PXD has 30% interest Driver Johnson Benedum Edward Joyce Midkiff Lone Star Pipeline PXD production throughput of ~50 MBPD Connect to all PXD gas processing plants Mont Belvieu fractionation capacity at ~2.1 MMBPD Current capacity: 320 MMCFPD 2 PXD production makes up ~16% of throughput PXD Acreage Existing NGL Pipeline 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 31

32 PIONEER S FOCUS ON INNOVATION AND TECHNOLOGY WILL DRIVE FURTHER EFFICIENCIES IN THE PERMIAN BASIN New technology initiatives are focused on improving productivity Machine learning and artificial intelligence 4-D fracture propagation modeling Predictive analytics Automation Bot technology (e.g., automate manual repeatable tasks) Drilling rig of the future Dynamic drill string modeling 4-D fracture propagation modeling Dynamic drill string modeling Real-time drilling prediction software Fiber optic subsurface measurement tools Partnering with national labs, universities and service companies 32

33 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 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 Water for Completion 33

34 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 34

35 PERMIAN BASIN TAKES THE GLOBAL STAGE Ghawar, Saudi Arabia Total Recoverable Resource (BBOE) Permian Basin, USA Burgan, Kuwait Safaniyah, Saudi Arabia Eagle Ford Shale, USA Produced To Date Midland Basin Delaware Basin U.S. hits all time high of oil production exceeding 10 MMBOPD November 2017 EIA Samotlorskoye, Russia Shaybah, Saudi Arabia Romashkinskoye, Russia ADCO, UAE Zuluf, Saudi Arabia Cantarell, Mexico 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 1) Total recoverable resource includes oil and gas for all fields Source: Wood Mackenzie for international fields; Permian Basin from internal estimates 35

36 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 36

37 U.S. LARGEST SHALE PLAYS Permian Basin Petrophysical analysis indicates significantly more oil in place in the Wolfcamp and Spraberry Shale intervals in the Midland Basin Permian Basin compared to other major U.S. shale oil plays Midland Basin ~3,000 of Shale South Texas Eagle Ford Colorado Niobrara North Dakota Bakken Pennsylvania Marcellus Delaware Basin Source: PXD Midland Basin Data Red Indicates Shale Oil 37

38 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 38

39 IMPACT OF HORIZONTAL DRILLING IN THE MIDLAND BASIN Midland Basin production has increased ~1.4 MMBOEPD since 2009 Hz From 2009 to 2012, production growth primarily attributable to increased vertical activity Post 2012, production growth driven by horizontal activity Source: IHS Energy 39

40 Daily Oil Production (MMBOPD) WTI Price ($/BBL) PERMIAN BASIN HORIZONTALS ARE A GAME CHANGER 3.0 The Permian Basin has produced >35 BBOE in the past 90 years with an estimated >150 BBOE recoverable resource remaining $ Permian Basin Oil Production $140 $120 $ Oil Price $ Horizontal Drilling Begins '00 '01 '02 '03 '04 '05 '06 '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 $60 $40 $20 $0 Source: Production data from EIA (U.S. tight oil production selected plays) through April 2018; historical WTI price from EIA 40

41 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 3.5 Permian Basin Nov OPEC Decision Source: EIA, Drilling Productivity Report, June 2018 Eagle Ford Bakken Niobrara Anadarko Other regions in EIA s Drilling Productivity Report 41

42 HORIZONTAL OIL RIG COUNT Peak: 1,115 U.S. 6/1/18: % vs. bottom Previous Peak: 349 6/1/18: % vs. bottom Permian Bottom: 247 Bottom: 116 The Permian Basin is operating more horizontal oil rigs than ever before Source: Baker Hughes 42

43 DEFINITIONS AND SUPPLEMENTAL INFORMATION Return on Capital Employed (ROCE) equals net income adjusted for tax-effected interest expense, net noncash MTM derivative gains and losses and other unusual items 1 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 forwardlooking 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. 1) Unusual items have historically included noncash property impairments, gain/loss on asset divestitures and tax-related items 43

44 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, 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 Revisions of previous estimates exclude price revisions. 44

45 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 These filings also can be obtained from the SEC by calling SEC

46 COMMON SHARE REPURCHASES The stock purchase program allows for up to $100 million of stock to be repurchased during 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. 46