INVESTOR PRESENTATION 3Q»2017

Q3 2018 Earnings Presentation November 1, 2018 INVESTOR PRESENTATION 3Q»2017 PARSLEYENERGY.COM

Forward Looking & Cautionary Statements Forward-Looking Statements The information in this presentation includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this presentation, the words could, believe, anticipate, intend, estimate, expect, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on Parsley Energy, Inc. s ( Parsley Energy, Parsley, or the Company ) current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, the production potential of our undeveloped acreage, cash flow and access to capital, the timing of development expenditures and the risk factors discussed in or referenced in our filings with the United States Securities and Exchange Commission ( SEC ), including our Annual Report on Form 10-K and our subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this presentation. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or cost increases. Industry and Market Data This presentation has been prepared by Parsley and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published independent sources. Although Parsley believes these third-party sources are reliable as of their respective dates, Parsley has not independently verified the accuracy or completeness of this information. Some data are also based on Parsley s good faith estimates, which are derived from its review of internal sources as well as the third-party sources described above. Accounting Standards Codification Topic 606, Revenue from Contracts with Customers ( ASC 606 ) Natural gas and natural gas liquids ( NGLs ) sales and associated production volumes for the three months ended September 30, 2018 reflect adjustments associated with Parsley s adoption of Accounting Standards Codification Topic 606, Revenue from Contracts with Customers ( ASC 606 ), effective January 1, 2018. Unless otherwise noted, all references to 3Q18 production volumes and per Boe unit costs likewise reflect this adoption, which has the effect of increasing certain natural gas and NGLs volumes and revenues, offset by a corresponding transportation and processing cost such that there is no change to reported net income. The recognition and presentation of oil volumes and associated revenues and expenses are unaffected by the adoption of ASC 606. For more information on ASC 606 and a reconciliation of 3Q18 production and unit costs under ASC 605 and as adjusted under ASC 606, please see Supplementary Slides. 2

Parsley Energy Overview Premier Permian Pure-Play Efficient and sustainable growth trend Elite return profile Economies of scale and core inventory depth Advantaged production flow and pricing Financial flexibility with strong balance sheet Economic uplift from minerals ownership 3Q18 Highlights Robust operating cash margin (1) Disciplined portfolio management Sustained operational momentum Reduced capital costs Permian Parsley Basin Energy Net Acreage Net Leasehold Acreage: ~200,000 (2) (96% Operated) ANDREWS Midland Basin: ~155,000 LEA Delaware Basin: ~45,000 Net Royalty Acreage: ~7,500 Delaware Basin REEVES WINKLER WARD PECOS ECTOR Central Basin Platform CRANE MARTIN MIDLAND Market Snapshot UPTON Midland Basin REAGAN NYSE Symbol: PE Market Cap: $7,419 MM (3) Net Debt: $1,851 MM (4) Enterprise Value: $9,270 MM (5) Share Count: 317 MM HOWARD GLASSCOCK Parsley Acreage (1) Operating cash margin is a non-gaap financial measure. For reconciliation of operating cash margin to the most directly comparable GAAP financial measure, please see Supplementary Slides; (2) As of 11/1/2018 pro forma for pending divestiture; (3) Calculated using fully diluted share count of 317 mm shares (280mm Class A shares plus 37mm Class B shares) as of 11/1/2018 and closing price as of 10/31/2018; (4) As of 9/30/2018 pro forma for expected proceeds of ~$165 million from divestitures announced 11/1/2018. Net Debt is a non-gaap financial measure defined as total debt less cash and cash equivalents; (5) Enterprise value is calculated as market capitalization plus net debt, where market capitalization is calculated as share price times the sum of Class A shares outstanding and Class B shares outstanding; Because non-controlling interest represents the portion of total book value of equity allocated to Class B shareholders, it is already represented in the enterprise value calculation by the inclusion of Class B shares in the calculation of market capitalization, and should not be added separately as a component of enterprise value. 3

Laying the Foundation 10-Year Lookback Achieve Scale Build Reinvestment Runway Horizontal Rig Count 20 16 12 8 4 Fastest to 100 MBoe/d (1) 7 th Largest Permian Rig Program (2) 125 100 75 50 25 Net Production (MBoe/d) Parsley Operating Area in 2008 Parsley Acreage % of Dev Inventory Drilled (5) % of Dev Inventory Remaining (5) Inventory Life at Current Pace (6) ANDREWS MARTIN Midland Basin HOWARD ECTOR GLASSCOCK 0 0 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Horizontal Rigs Net Production (MBoe/d) Central Basin Platform MIDLAND Create Shareholder Value Compound Annual Growth Rate 50% 25% 0% -25% One of 5 operators to generate positive shareholder return since Parsley IPO (4) CRANE Delaware Basin UPTON REAGAN -50% Production per DAS 2014-18E CAGR (3) (4) TSR CAGR from PE IPO REEVES PECOS (1) Bloomberg; Based on number of reporting periods for production between 10 MBoe/d and 100 MBoe/d; Peers include oil-focused E&Ps (oil represents at least 40% of total production) for which relevant production data is available; Peers include AREX, BCEI, CDEV, CLR, CPE, CRZO, CXO, FANG, HK, JAG, MTDR, NOG, OAS, PDCE, PetroHawk, ROSE, RSPP, SM, SN, SRCI, and WLL; Production adjusted for non-controlling interest where applicable; (2) DrillingInfo as of October 19, 2018; (3) Production per debt-adjusted share (DAS) from Evercore ISI as of October 22, 2018; Peers include APA, APC, AR, CHK, CLR, CNQ-TSE, COG, CPE, CXO, DVN, ECA, EGN, EOG, EQT, FANG, MRO, NBL, NFX, OAS, PXD, QEP, RRC, SU-TSE, SWN, WLL, WPX, and XEC; (4) FactSet as of October 30, 2018; Parsley shares priced at $18.50 per share on May 22, 2014; (5) Development inventory includes operated locations in Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones; As of 11/1/2018 pro forma for pending divestiture; (6) Based on YTD 2018 activity levels in each development area as of October 30, 2018. 4

Organic Path to Self-Funded Growth Parsley s Investment Framework Guiding Principles Discipline require strong return on incremental development dollar Foresight anticipate constraints and capture counter-cyclical opportunities Stability manage financial and operational risk to ensure execution of plan Target Outcomes Milestones Mid-teens after-tax CROCI (1)(2) Free cash flow by YE19 (2)(3) Enhanced operational efficiency Application 2019 Outline Process Steady development pace Increasing operational efficiency Intensive cost control Stable development pace until self-funded growth achieved Excess cash flow creates growth rate optionality Top-tier corporate returns Increasing free cash flow Robust production growth per share $0 2017 2018 Steady development pace accelerates progress toward free cash flow generation Outspend (3) Operated Horizontal Rigs Frac Crews (1) Cash return on capital invested (CROCI) is a non-gaap financial measure and is defined as ((cash flow from operations + after-tax interest expense) / (average gross PP&E + average non-cash working capital)); (2) At NYMEX strip prices as of publication date; (3) Free cash flow/outspend is a non-gaap financial measure and is defined as (cash flow from operations before changes in operating assets and liabilities - development capital expenditures). 5

Operational Momentum Building Increasing Operational Velocity New Efficiency Thresholds 1,400 3Q18 Records 1,200 Parsley record: Over 420,000 stimulated lateral feet and 46 wells placed on production 1,000 Permian Basin record: Drilled longest one-run (2) slimhole lateral (2.5 mile lateral in Glasscock County) Feet 800 Efficient Drilling on Longer Laterals 10,000 50% 600 400 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 Stimulated Lateral Feet per Operational Day per Crew Drilled Feet per Operational Day per Rig (1) (1) Average Lateral Length (ft.) 9,000 8,000 7,000 6,000 5,000 4,000 Percentage of one-run laterals increased alongside increase in lateral lengths 2014 2015 2016 2017 2018 YTD 45% 40% 35% 30% 25% 20% Percent of One-Run Laterals (1) Operational day measured as days equipment is active. Does not include mobilization or other idle time; (2) One-run lateral defined as a lateral drilled in one trip without any trips back up hole for various equipment maintenance or replacement needs. 6

Intensive Cost Control Reduced Drilling & Completion Costs Low Operating Costs $1,100 D&C capex per lateral foot declined 9% Q/Q $22 $20 Drilling & Completion Capital Expenditures per Lateral Foot ($/ft) (1) $1,000 $900 $800 $700 Operating costs per Boe below $10 $18 $16 $14 $12 $10 Operating Costs ($/Boe) (2) $600 1Q18 2Q18 3Q18 2014 2015 2016 2017 2018 $8 Capital costs driven lower by shorter cycle times, longer laterals, and increased regional sand usage Peer-leading LOE and company-record G&A keep unit operating costs near company-lows (1) Drilling & Completion Capital Expenditures per Lateral Foot calculated using company reported capital expenditures (accrual basis) and announced lateral lengths per the respective quarterly earnings releases; Not normalized for Midland and Delaware activity mix; (2) Per-unit operating costs include lease operating expenses, cash based general & administrative expenses (exclusive of stock-based compensation), and production and ad valorem taxes. Note: transportation and processing costs excluded for comparison purposes. 7

Capitalizing on Counter-Cyclical Investments Accelerating Development During Lower Service Cost Environment Enabled Robust Oil Growth in Higher Commodity Price Environment Operated Horizontal Rigs 18 16 14 12 10 8 More than doubled operated rig count 178 170 162 154 146 138 Oil & Gas Extraction Producer Price Index (Rolling 2-Month Average) (1) Net Oil Production (MBo/d) 75 70 65 60 55 50 45 More than doubled oil volumes $80 $76 $72 $68 $64 $60 $56 WTI Cushing ($/Bo) (2) 6 130 40 $52 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 35 $48 In light of anticipated tightness in the market for highspecification drilling rigs, Parsley proactively secured all of the rigs necessary to execute its 2017 drilling program. 30 $44 - Parsley 2Q17 Earnings Release 25 $40 3Q18 2Q18 1Q18 4Q17 3Q17 2Q17 1Q17 4Q16 (1) U.S. Bureau of Labor Statistics, Producer Price Index by Industry: Oil and Gas Extraction [PCU21112111], retrieved from FRED, Federal Reserve Bank of St. Louis; (2) Bloomberg. 8

Oil Flowing at Advantaged Price Marketing strategy centered around two guiding principles: dependability and diversification Finalized previously announced marketing agreements to bolster takeaway runway and support growth plans Proactive marketing strategy continues to deliver flow assurance and strong pricing Ongoing exposure to Gulf Coast pricing mitigates impact of Midland differentials and translates to healthy projected realizations during Permian infrastructure buildout Negotiated favorable pricing on longerterm agreements Expect ~$2/Bbl differential to Gulf Coast price on barrels covered by firm transport in 2020 (3) Additional diversification through exposure to international pricing Expect consistently strong realizations even during period of relative Midland price weakness Unhedged Oil Price Realization ($/Bo) Parsley Unhedged Oil Price Realization ($/Bo) $65 $60 $55 $50 $80 $60 $40 $20 $0 -$20 -$40 Leading Oil Price Realization (1) (2) PE Midland PE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 3Q18 2Q18 Historical & Illustrative Oil Price Realizations 1H18 2H18E 1H19E 2H19E 1H20E 2H20E (4) PE Unhedged Oil Price Realization (Net of Gathering Fee) Midland/Gulf Coast Forward Differential (5) $40 $30 $20 $10 $0 -$10 -$20 Market Implied Midland/Gulf Coast Differential ($/Bo) (1) PE realized price shown net of gathering fee. Peers include CDEV, CPE, CXO, EGN, FANG, HK, LPI, MTDR, and SM. Permian only oil realizations shown where applicable; (2) Midland price represents Bloomberg-sourced 3Q18 average WTI Midland price; (3) Differential to Gulf Coast refers to expected realized price relative to Magellan East Houston (MEH) benchmark and excludes gathering fees; (4) Weighted average realization based on anticipated exposure to MEH, Cushing, and Midland benchmarks using Bloomberg-sourced futures pricing for each as of 10/26/2018; net of gathering fee at assumed $1.25/Bo; Range primarily based on pipeline start-up timing and variable pricing agreements; (5) Midland/Gulf Coast forward differential based on Bloomberg-sourced futures pricing for Midland and MEH benchmarks as of 10/26/2018. 9

Operational Spotlight - Martin County Recent Martin County well results showcase top-tier rock quality: Strong results from recent three-well projects targeting the Wolfcamp A and B formations: Average IP30 of 1,560 Boe/d (80% oil) (Hayden) Parsley-record 30-day oil rate for a three-well pad Ramping Martin Co. Development Midland Basin MARTIN HOWARD Average IP30 of 1,435 Boe/d (74% oil) (Strain Ranch) Both pads outpacing industry average Martin County productivity Robust Well Performance (1) MIDLAND Cumulative Oil Production (MBo) 100 90 80 70 60 50 40 30 20 10 0 0 30 60 90 120 Martin County Industry Average (2017-2018) Strain Ranch 3-Well Average Hayden 3-Well Average Parsley Acreage Hayden Pad Strain Ranch Pad Water Recycling Center Successful water recycling pilot supports increased development: Over 100K barrels of recycled water utilized during Hayden pad completion Strong results suggest no apparent productivity degradation GLASSCOCK (1) Normalized to 10,000 lateral; Martin County Industry Average calculated using DrillingInfo and represents average of all Martin County horizontal wells placed on production between January 1, 2017 and August 31, 2018. 10

Pruning the Portfolio Committed to the Core Bringing Tail-End Value Forward MARTIN HOWARD Targeted Divestitures (1) Midland Basin Summary: Monetized portion of central Reagan, southern Upton, and northern Howard acreage, comprised of tail-end inventory MIDLAND GLASSCOCK Transaction Details Net Acreage: ~11,850 Net Acres Net Development Locations (2) : 256 Locations (~5,100 Avg. Lateral) 3Q18 Net Production: ~1,200 Boe/d (~55% Oil) Cash Proceeds: ~$170 million Expected Close Dates: By Year-end 2018 UPTON Disciplined pruning program brings value forward and recycles capital into high-return areas Parsley Acreage Divested Acreage REAGAN IRION (1) Includes recent divestitures with signed purchase and sales agreements and select acreage trade where Parsley received cash proceeds as part of the transaction; (2) Development inventory includes operated locations in Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones. 11

Strong, Flexible Financial Position Advantaged Liquidity Profile (1) Liquidity ($MM) Cash on Hand Borrowing Base Availability Drawn on Revolver (%) $1,400 14% $1,200 $1,000 $800 $600 $400 $200 $0 (2) PE Peer 1 Peer 2 Peer 3 Peer 4 12% 10% 8% 6% 4% 2% 0% Percent Drawn on Revolver Favorable Debt Maturity Schedule $2,300 $1,300 Favorable debt maturity schedule with earliest notes maturity in 2024 Weighted average cost of debt has dropped ~200 bps since mid-2016 Peer-leading (1) liquidity of $1.3 billion (2) Remaining Borrowing Base $1,000 $1,100 $450 2H25 $700 Healthy leverage ratio of 1.5x (3) LTM EBITDAX Committed Amount $400 $650 1H25 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Revolving Credit Facility ($MM) Senior Notes ($MM) (1) Permian SMID-Cap peers include CDEV, CPE, JAG, and LPI. Calculated as availability on committed portion of borrowing base plus cash and cash equivalents. Peer data obtained from 2Q18 filings and pro forma for subsequent debt offerings, acquisitions, and divestitures; (2) As of September 30, 2018 and pro forma for expected proceeds of ~$165 million from subsequent acreage divestiture and trade announced 11/1/2018; (3) Leverage ratio calculated as net debt at September 30, 2018 pro forma for expected proceeds of ~$165 million from subsequent divestiture and trade announced 11/1/2018 divided by last twelve-month Adjusted EBITDAX; Adjusted EBITDAX is not presented in accordance with generally accepted accounting principles in the United States ( GAAP ). For reconciliation of the non-gaap financial measure of adjusted EBITDAX to the most directly comparable GAAP financial measure, please see the Supplementary Slides. 12

Guidance Summary Production 2018E (Unchanged) Annual Net Oil Production (MBo/d) 68.0-70.5 Annual Net Production (MBoe/d) (1) 106.0-111.0 Capital Program Total Development Expenditures ($MM) $1,650 - $1,750 Drilling & Completion (% of Total) 85 90% Facilities, Infrastructure & Other (% of Total) 10 15% Disciplined Approach Commitment to 2018 capital budget is priority Reduced 3Q18 service and equipment utilization to accommodate efficiency gains Recently announced divestitures do not impact 2018 guidance Activity Gross Operated Horizontal POPs (2) ~165 4Q18 rig and frac spread utilization rate will be dictated by 2018 capital budget Midland Basin (% of Total) ~75% Delaware Basin (% of Total) ~25% 5 90% Average Lateral Length ~9,500 Average Working Interest 95 97% Net Operated Horizontal POPs (2) 157-160 80% Units Costs 70% Lease Operating Expenses ($/Boe) (1) $3.50 - $4.25 Cash G&A ($/Boe) (1) $3.25 - $3.65 Production & Ad Valorem Taxes (% of Revenue) 6.0 7.0% 0 1Q18 2Q18 3Q18 4Q18E Dedicated Frac Spreads Frac Spread Utilization 60% (1) Incorporates adoption of ASC 606; (2) Wells placed on production. 13

Supplementary Slides

High Rankings on Key Value Drivers Relative Rank Operating Margin (1)(6) Recycle Horizontal Rigs 2014-2018E % Oil (2)(6) Ratio (3)(6) In Lower-48 (4)(6) DAPS Growth (5) Asset Quality & Operational Efficiency Operators with Top Quartile Valuation (7) Operators with Interquartile Valuation (7) Operators with Bottom Quartile Valuation (7) Commodity Weighting Scale & Growth Parsley Energy Average Rank of Operators with Top Quartile Valuation (7) Average Rank of Operators with Bottom Quartile Valuation (7) (1) SGS E&P Comp Sheets (October 19, 2018). 2Q18 Operating Margin; (2) FactSet; Based on 2Q18 reported production; (3) SGS E&P Comp Sheets (October 19, 2018). Recycle ratio is equal to operating margin divided by PD F&D. F&D costs based on 2017 data and operating margin based on 2Q18. PE recycle ratio includes actual 2017 PD F&D/Boe of $12.10; (4) DrillingInfo as of October 20, 2018; (5) Debt-adjusted per share (DAPS) production growth CAGR 2014 to 2018e. Evercore ISI October 22, 2018. Peers include APA, APC, AR, CHK, CLR, COG, CPE, CXO, DVN, ECA, EOG, FANG, MRO, NBL, NFX, OAS, PXD, QEP, RRC, SWN, WLL, WPX, and XEC; (6) Peers include APA, APC, AR, AXAS, CDEV, CHK, CLR, COG, CPE, CRC, CRK, CRZO, CXO, DVN, ECA, ECR, EOG, EPE, ESTE, FANG, GDP, GPOR, HES, JAG, LGCY, LONE, LPI, MCF, MRO, MTDR, MUR, NBL, NFX, OAS, OXY, PDCE, PQUE, PXD, QEP, REI, REN, RRC, SD, SM, SN, SRCI, SWN, WLL, WPX, WRD, WTI, XEC, and XOG; (7) Valuations from FactSet as of October 20, 2018 defined as Enterprise Value divided by consensus 2018 EBITDAX estimate. 15

High Margin Growth Trend Steep production ramp accompanied by robust margin expansion Retained almost 80% of healthy realized price as marketing advantages, operating cost compression, and scale benefits flow through Strong Growth and Expanding Margins Set Pace Among Peers (3) 140 84% $45 120 72% $40 Net Production (MBoe/d) 100 80 60 40 14% quarterly production CAGR since IPO (2) 60% 48% 36% 24% Operating Cash Margin Percentage (1) 2Q18 Operating Margin ($/Boe) (4) $35 $30 $25 $20 $15 $10 20 12% $5 0 2015 2016 2017 2018 0% $0-40% -20% 0% 20% 40% 60% 80% 100% Historical 2-Year Production CAGR (5) (1) Operating cash margin percentage is not presented in accordance with generally accepted accounting principles in the United States ( GAAP ). For a reconciliation to the most directly comparable GAAP financial measure, please see Operating Cash Margin Reconciliation in the Supplementary Slides. Operating cash margin percentage calculated as operating cash margin per Boe divided by realized price per Boe excluding hedges. Operating cash margin defined as realized price per Boe excluding hedges less per-unit operating costs. Per-unit operating costs include lease operating expenses, cash based general & administrative expenses (exclusive of stock-based compensation), production and ad valorem taxes, and, if recorded during the period, transportation and processing costs. For all periods in 2018, operating cash margin percentage reflects adoption of ASC 606; (2) May 23, 2014; (3) Peers include APA, APC, AR, AREX, AXAS, CHK, CLR, COG, CPE, CRC, CRK, CRZO, CXO, DNR, DVN, ECA, ECR, EGN, EOG, EPE, ESTE, FANG, GDP, GPOR, GST, HES, HK, HPR, JONE, LGCY, LONE, LPI, MCF, MRO, MTDR, MUR, NBL, NFX, NOG, OAS, OXY, PDCE, PQUE, PXD, QEP, REI, REN, RRC, SD, SM, SN, SRCI, SWN, TALO, WLL, WPX, WTI, and XEC; (4) 2Q18 unhedged operating margins as reported in SGS E&P Comp Sheets; operating margin is defined as realized price per Boe excluding hedges less per-unit lease operating expenses, transportation & gathering costs, total general & administrative expenses, production and ad valorem taxes, and other operating expenses; (5) FactSet; 2-Year CAGR calculated using 2Q18 and 2Q16 reported total production. 16

The Right Balance Elite Combination of Growth and Returns (1) 14% Cash Return on Capital Invested, Average 2015-17 (2) 12% 10% 8% 6% 4% 2% Median: -3% 0% -40% -30% -20% -10% 0% 10% 20% 30% 40% Production per debt-adjusted share, 2015-17 CAGR Median: 6% Top-tier returns throughout during intensive growth and asset expansion phase (1) Goldman Sachs Global Investment Research; October 2018; Peers include APA, APC, AR, CHK, CLR, CNX, COG, COP, CRC, CRZO, CXO, DNR, DVN, ECA, EOG, EQT, FANG, GPOR, HES, LPI, MRO, MUR, NBL, NFX, OAS, OXY, PDCE, PXD, QEP, RRC, SWN, WLL, WPX, and XEC; (2) Cash Return on Capital Invested (CROCI) is a non-gaap financial measure and Goldman Sachs Global Investment Research defines it as ((cash flow from operations + after-tax interest expense) / (gross PP&E + goodwill + working capital and other assets)). 17

Capturing the NGL Upswing Favorable NGL Dynamics Harvesting Higher NGL Prices $40 High quality NGL barrel Aligned contract structure Favorable recovery rates Ample partner-controlled fractionation capacity NGL Realizations Excluding Effect of Hedges ($/Bbl) $35 $30 $25 $20 $15 $10 Realized 88% of Mont Belvieu price in 3Q18 3Q18 2Q18 1Q18 4Q17 3Q17 2Q17 1Q17 4Q16 3Q16 OPIS Mt. Belvieu NGL Basket(1) PE Peers (2) (1) OPIS Mont Belvieu NGL Basket calculated with historical NGL prices from Bloomberg and weighting consistent with ICE Futures contract definition of NGL Basket, OPIS Mt. Belvieu Non-TET Future contract; 42% ethane, 28% propane, 11% butane, 6% iso-butane, and 13% natural gasoline; (2) Quarterly filings; peers include CDEV, EGN, FANG, JAG, LPI, and PXD. 18

Oil Hedge Position Open Crude Oil Derivatives Positions 4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 OPTION CONTRACTS CUSHING Put Spreads Cushing (MBbls/d) (1) 37.5 20.0 19.8 24.5 24.5 Long Put Price ($/Bbl) $49.67 $54.17 $54.17 $58.83 $58.83 Short Put Price ($/Bbl) $39.67 $44.17 $44.17 $48.83 $48.83 Aligning hedges with regional price exposure Hedge structure retains upside to higher oil prices Crude Realizations Not Constrained by Swaps (7) 80% $70 Three Way Collars - Cushing (MBbls/d) (2) 31.0 8.3 8.2 9.8 9.8 Short Call Price ($/Bbl) $75.65 $80.40 $80.40 $80.33 $80.33 Long Put Price ($/Bbl) $50.00 $50.00 $50.00 $50.83 $50.83 Short Put Price ($/Bbl) $40.00 $40.00 $40.00 $40.83 $40.83 70% $65 Collars Cushing (MBbls/d) (3) 3.0 Short Call Price ($/Bbl) $61.31 Long Put Price ($/Bbl) $45.67 MIDLAND Put Spreads Midland (MBbls/d) (1) 11.7 14.8 4.9 4.9 Long Put Price ($/Bbl) $50.71 $50.56 $60.00 $60.00 Short Put Price ($/Bbl) $40.71 $40.56 $50.00 $50.00 MEH Put Spreads MEH (MBbls/d) (1) 3.3 3.3 8.2 8.2 5.0 4.9 Long Put Price ($/Bbl) $70.00 $70.00 $64.00 $64.00 $70.00 $70.00 Short Put Price ($/Bbl) $60.00 $60.00 $54.00 $54.00 $60.00 $60.00 Total Option Contracts (MBbls/d) 71.5 43.3 46.1 47.4 47.4 5.0 4.9 Oil Production Covered by Swaps 60% 50% 40% 30% 20% $60 $55 $50 $45 $40 Dollar per Barrel of Oil Premium Realization ($MM) (4) ($19.1) ($12.4) ($13.3) ($13.6) ($13.6) ($1.6) ($1.6) BASIS SWAPS Midland-Cushing Basis Swaps (MBbls/d) (5) 18.5 21.7 8.9 Swap Price ($/Bbl) ($3.76) ($8.42) ($8.94) MEH-Cushing Basis Swaps (MBbls/d) (5) 2.2 2.1 2.1 2.1 Swap Price ($/Bbl) $5.10 $5.10 $5.10 $5.10 ROLLFACTOR SWAPS Rollfactor Swaps (MBbls/d) (6) 15.0 Swap Price ($/Bbl) $0.60 10% 0% $35 $30 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 PE 4Q18E Swap Coverage (Left Axis) 2019E Swap Coverage (Left Axis) 4Q18E Swap Price (Right Axis) 2019E Swap Price (Right Axis) 4Q18 WTI Strip (Right Axis) 2019 WTI Strip (Right Axis) Hedge positions as of 11/1/2018. Prices represent the weighted average price of contracts scheduled for settlement during the period; (1) When the reference price (WTI, Midland, or MEH) is above the long put price, Parsley receives the reference price. When the reference price is between the long put price and the short put price, Parsley receives the long put price. When the reference price is below the short put price, Parsley receives the reference price plus the difference between the short put price and the long put price; (2) Functions similarly to put spreads except when the reference price is at or above the call price, Parsley receives the call price; (3) When the reference price (WTI) is above the call price, Parsley receives the call price. When the reference price is below the long put price, Parsley receives the long put price. When the reference price is between the short call and long put prices, Parsley receives the reference price; (4) Premium realizations represent net premiums paid (including deferred premiums), which are recognized as a loss in the period of settlement; (5) Parsley receives the swap price; (6) These positions hedge the timing risk associated with Parsley s physical sales. Parsley generally sells crude oil for the delivery month at a sales price based on the average reference price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month, and the following month during the period when the delivery month is the first month; (7) BMO Capital Markets; Peers include CPE, CXO, FANG, JAG, LPI, and REN. WTI strip from FactSet as October 26, 2018. 19

Adjusted EBIDAX Reconciliation Unaudited, in thousands Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net income: Net income (loss) attributable to Parsley Energy, Inc. stockholders $113,309 ($13,333) $315,354 $56,855 Net income (loss) attributable to noncontrolling interests 20,840 (1,828) 65,216 22,068 Depreciation, depletion and amortization 157,352 94,819 424,103 247,104 Exploration amd abandonment costs 11,140 88 19,917 4,223 Interest expense, net 32,854 22,879 98,580 64,979 Interest income (1,055) (1,013) (4,864) (5,562) Income tax expense (benefit) 32,454 (5,080) 89,022 25,538 EBITDAX $366,894 $96,532 $1,007,328 $415,205 Change in TRA liability - - 82 20,549 Stock-based compensation 4,686 5,170 15,118 14,630 Acquisition costs - 2,449 2 10,969 Gain on sale of property (1,383) - (6,438) - Accretion of asset retirement obligations 361 268 1,074 597 Loss on early extinguishment of debt - - - 3,891 Inventory write down 451-495 - Loss (gain) on derivatives 22,514 61,955 42,773 (6,175) Net settlements on derivative instruments 9,376 10,982 (516) 15,654 Net premiums on options that settled during the period (17,853) (12,487) (52,451) (22,404) Adjusted EBITDAX $385,046 $164,869 $1,007,467 $452,916 Note: Certain reclassifications to prior period amounts have been made to conform with current presentation. 20

Operating Cash Margin Reconciliation $ in thousands Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 Net income (loss) attributable to Parsley Energy, Inc. stockholders $113,309 ($13,333) $315,354 $56,855 Net income (loss) attributable to noncontrolling interests 20,840 (1,828) 65,216 22,068 Income tax expense (benefit) 32,454 (5,080) 89,022 25,538 Other revenues (2,369) (8) (7,916) (3,533) Depreciation, depletion and amortization 157,352 94,819 424,103 247,104 Exploration and abandonment costs 11,140 88 19,917 4,223 Stock-based compensation 4,686 5,170 15,118 14,630 Acquisition costs - 2,449 2 10,969 Accretion of asset retirement obligations 361 268 1,074 597 Other operating expenses 6,129 2,419 10,781 8,275 Interest expense, net 32,854 22,879 98,580 64,979 Gain on sale of property (1,383) - (6,438) - Prepayment premium on extinguishment of debt - - - 3,891 Derivative loss (gain) 22,514 61,955 42,773 (6,175) Change in TRA liability - - 82 20,549 Interest income (1,055) (1,013) (4,864) (5,562) Other expense (income) 76 (508) (459) (1,281) Operating cash margin $396,908 $168,277 $1,062,345 $463,127 Operating cash margin per Boe $37.13 $25.57 $36.75 $26.61 Average price per Boe, without realized derivatives $47.58 $36.62 $47.17 $37.47 Operating cash margin percentage 78% 70% 78% 71% 21

Impact of ASC 606 Adoption Three Months Ended September 30, 2018 ASC 605 Adjustment ASC 606 Production revenues (in thousands): Oil sales $424,549 -- $424,549 Natural gas sales 11,509 1,301 12,810 Natural gas liquids sales 64,100 7,194 71,294 Total production revenues 500,158 8,495 508,653 Operating expenses Transportation and processing costs -- 8,495 8,495 Production revenues less transportation and processing costs $500,158 -- $500,158 Net income attributable to Parsley, Inc. stockholders (in thousands) $113,309 -- $113,309 Production: Oil (MBbls) 6,763 -- 6,763 Natural gas (MMcf) 8,791 1,087 9,878 Natural gas liquids (MBbls) 2,012 269 2,281 Total (MBoe) 10,240 450 10,690 Average daily production volume: Oil (Bbls) 73,511 -- 73,511 Natural gas (Mcf) 95,554 11,816 107,370 Natural gas liquids (Bbls) 21,870 2,923 24,793 Total (Boe) 111,304 4,892 116,196 Certain unit costs (per Boe): Lease operating expenses $3.88 ($0.16) $3.72 Transportation and processing costs -- $0.79 $0.79 Production and ad valorem taxes $2.99 ($0.13) $2.86 Depreciation, depletion and amortization $15.37 ($0.65) $14.72 General and administrative expenses (including stock-based compensation) $3.67 ($0.16) $3.51 General and administrative expenses (cash based) $3.21 ($0.14) $3.07 22

Reserves Disclosure Oil & Gas Reserves This presentation provides disclosure of Parsley s proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. In this presentation, proved reserves attributable to Parsley as of 12/31/2017 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on SEC pricing, as adjusted for market differentials, transportation fees, and quality, of $49.17 / Bbl crude, $2.53 / Mcf gas, and $22.20/ Bbl NGL. References to our estimated proved reserves as of 12/31/2017 are derived from our proved reserve report audited by Netherland, Sewell & Associates, Inc. ( NSAI ). We may use the term expected ultimate recoveries ( EURs ) 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 Parsley from including in filings with the SEC. Unless otherwise stated in this presentation, such estimates have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to demonstrate what we believe to be the potential for future drilling and production by the Company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differ substantially. In addition, we have made no commitment to drill all of the drilling locations. Ultimate recoveries will be dependent upon numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest leases. Our estimates may change significantly as development of our properties provides additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Our related expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases. Unless otherwise noted, Net Present Value ( NPV ) estimates are before taxes and assume the Company generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include facilities, land, seismic, general and administrative ( G&A ) or other corporate level costs. Proved Developed Finding and Development ( F&D ) Costs Parsley uses proved developed F&D, oil and gas proved developed F&D, and drillbit F&D costs as an indicator of capital efficiency, in that it measures Parsley s costs to add proved developed reserves on a per Boe basis. Proved developed F&D is calculated as total 2017 capital expenditures (including Infrastructure and Other) divided by total 2017 proved developed reserves additions and revisions (technical and pricing). Drillbit F&D is calculated as total 2017 capital expenditures (including infrastructure and Other), divided by total 2017 reserves additions and revisions (technical and pricing). Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to development the company s reserves. Oil and gas PD F&D cost calculated by dividing annual development capital expenditures by year-over-year proved developed producing and proved developed non-producing reserve additions, and includes reclassifications and technical and pricing revisions, but excludes acquisitions and divestitures. 23