INVESTOR PRESENTATION 3Q»2017

Q4 2018 Earnings Presentation February 21, 2019 INVESTOR PRESENTATION 3Q»2017

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 and year ended December 31, 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 4Q18 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 4Q18 production and unit costs under ASC 605 and as adjusted under ASC 606, please see the Supplementary Slides. 2

Parsley Energy Overview Premier Permian Pure-Play Economies of scale and core inventory depth Elite return profile Efficient and sustainable growth Advantaged production flow and pricing Financial flexibility with strong balance sheet Economic uplift from minerals ownership 4Q18 Highlights Posted strong operating cash margin (1) Furthered operational efficiency gains Showcased top-tier technical ability Unveiled disciplined 2019 program Permian Parsley Basin Energy Net Acreage Net Leasehold Acreage: ~192,000 (2) (97% Operated) ANDREWS Midland Basin: ~150,000 LEA Delaware Basin: ~42,000 Net Royalty Acreage: ~7,600 Delaware Basin REEVES WINKLER WARD PECOS ECTOR Central Basin Platform CRANE MARTIN MIDLAND UPTON Market Snapshot (3) Midland Basin REAGAN NYSE Symbol: PE Market Cap: $5,872 MM Net Debt: $2,021 MM Enterprise Value: $7,893 MM Share Count: 317 MM HOWARD GLASSCOCK Parsley Acreage (1) Operating cash margin percentage is not presented in accordance with generally accepted accounting principles in the United States ( GAAP ). For a reconciliation of operating cash margin to the most directly comparable GAAP financial measure, please see the Supplementary Slides; (2) As of 12/31/2018 pro forma for 2019 acreage expirations associated with 4Q18 non-cash leasehold impairment expense; (3) Market capitalization calculated using fully diluted share count of 317 MM shares (280 MM Class A shares plus 37 MM Class B shares) as of 2/21/2019 and closing price as of 2/20/2019. Net debt as of 12/31/2018. Net Debt is a non-gaap financial measure defined as total debt less cash and cash equivalents. 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

2018 Highlights Expanded margins through marketing advantages, operating cost compression, and scale benefits $64 Leading Oil Price Realizations (2) Proactive marketing strategy delivered flow assurance and strong realized pricing Compressed operating costs, including companyrecord LOE per Boe and cash G&A per Boe Optimized acreage portfolio through integration efforts, accretive acreage trades, and opportunistic divestitures Set new efficiency thresholds, enabling more wells to be drilled and completed with less equipment Unhedged Oil Price Realization ($/Bo) $63 $62 $61 $60 $59 $58 $57 PE Parsley realized positive pricing uplift versus local Midland prices in 2018 Peers (3) 1Q18 3Q18 Enhanced Drilling and Completion Efficiency Robust Operating Cash Margin Feet 1,400 1,200 1,000 800 600 400 200 0 Drilling efficiency improved 13% YoY Completion efficiency improved 27% YoY Drilled Feet per Operational Stimulated Lateral Feet per Operational Day per Rig(1) Day per Crew (1) 2017 2018 Per-Unit Operating Costs ($/Boe) $16 $15 $14 $13 $12 $11 $10 $9 $8 2015 2016 2017 2018 80% 75% 70% 65% 60% 55% 50% 45% 40% (4) (5) Per-Unit Operating Costs ($/Boe) Operating Cash Margin (%) (1) Operational day measured as days equipment is active and does not include mobilization or other idle time; (2) Company filings. PE realized prices shown net of gathering fees; (3) Peers include CDEV, CPE, CXO, EGN, FANG, HK, JAG, LPI, MTDR, and SM. Permian only oil realizations shown where applicable; (4) Per-unit operating costs include lease operating expenses, cash based general and administrative expenses (exclusive of stock-based compensation), and production and ad valorem taxes. Transportation and processing costs are excluded from 2018 to normalize for the period over period impacts of adopting ASC 606; (5) Operating cash margin percentage is a non-gaap financial measure. For a reconciliation to the most directly comparable GAAP financial measure, please see 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 including transportation and processing costs. 4 Operating Cash Margin (%)

Setting the Course for 2019 & Beyond Guiding Principles provided foundation For an optimal 2019 Action Plan And Accountability will help achieve goals and Compelling Long-Term Targets Rate of Return ( ROR )-driven approach to well selection Improve capital efficiency by 8-10%+ YoY (1) Discipline Accelerate timeline to self-funded growth Outspend by less than $250 million in any oil price environment (2) Further increase visibility on management and shareholder alignment Defend and extend operational efficiency gains Addition of corporate returns metric to 2019 incentive plan Increase footage drilled/completed per rig/crew over 2018 levels Health, Safety, & Environmental Excellence Stability Work with high-performing service partners on pricing and contracting Hedge to protect cash flow and balance sheet while retaining oil price upside Improve capital efficiency by 8-10%+ YoY (1) Outspend by less than $250 million in any oil price environment (2) Increasing Free Cash Flow Differentiated Cash Flow Growth per Share Sustain culture that promotes and prioritizes community stewardship Collaborate with Permian Strategic Partnership; publish Sustainability Report by year-end 2019 Top-Tier Corporate Returns Foresight Leverage legacy water infrastructure investments Exercise patience on incremental crude transport agreements Increase 3 rd party water revenues and/or explore strategic alternatives Deliver healthy long-term realized oil prices while limiting minimum volume commitments (MVCs) (1) Capital efficiency calculated as barrels of organic oil production added (Q4 1 /Q4 0, adjusted for proved developed producing ( PDP ) oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed in 4Q18; (2) Outspend is a non-gaap financial measure and is defined as (cash flow from operations before changes in operating assets and liabilities less development capital expenditures). 5

Organic Path to Self-Funded Growth Accelerating Free Cash Flow by Prioritizing ROR Inventory depth enables shift in development approach ROR focus pulls forward timing of sustainable free cash flow (1) Boosting Capital Efficiency 2019 Action Plan targets 8-10%+ YoY increase in capital efficiency (3) ROR 2019 Action Plan 2017-2018 Development Approach Productivity Improvements Optimizing completions Expected Capex Savings Lower service and equipment costs Increasing average proppant loading ~15% increase in 10-15% YoY average lateral length Wider spacing in ~75% of proppant select targets sourced from regional sand mines 4Q19 1H20 Free Cash Flow Timing (1)(2) Compressed stage follow-up trials Fewer new-build facilities; more Increasing Density (Wells / Section / Bench) Shifting mix to northern Midland Basin add-ons (1) Free cash flow is a non-gaap financial measure and is defined as cash flow from operations before changes in operating assets and liabilities; (2) At NYMEX WTI price of $50-$55/Bbl in 2019; (3) Capital efficiency calculated as barrels of organic oil production added (Q4 1 /Q4 0, adjusted for PDP oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed in 4Q18. 6

Long Reinvestment Runway Provides Development Optionality 2019 Action Plan targets 8-10%+ YoY increase in capital efficiency Durable, geographically balanced inventory enables shift to a more ROR-focused development approach in 2019 ANDREWS MARTIN Parsley Drill Spacing Unit ( DSU ) (1) Other Parsley Acreage (167,000 net acres) (2) (25,000 net acres) (2) Development Inventory Drilled (1) 2019E Development Program (2) Inventory Life at 2019E Pace (3) DSU Development Inventory Drilled (3) 2018 HOWARD DSU Development Program (3) 2019E Development Program (4) Remaining DSU Inventory Life at 2019E Pace (4)(5) Higher concentration of activity in Martin, Midland, and Upton Counties Combination of upsized fracs and wider spacing in select areas Central Basin Platform HOWARD Over a decade of running room in each distinct core geography at 2019 development patterns ECTOR 2017-2018 Development Approach MIDLAND Geographically balanced program Emphasis on resource discovery and delineation GLASSCOCK WARD CRANE REEVES UPTON REAGAN PECOS (1) Leasehold where Parsley can drill or propose drilling horizontal wells with lateral lengths equal to or greater than 1-mile; (2) As of 12/31/2018 pro forma for 2019 acreage expirations associated with 4Q18 abandonment costs; (3) Development inventory includes operated locations in Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones in defined DSUs. As of 12/31/2018. Darker shade of blue represents actual 2018 development program; (4) Based on 2019E activity levels in each development area as of 2/21/2019; (5) Bottom of inventory range represents development of inventory in defined DSUs utilizing increased proppant and wider spacing configuration, consistent with 2019 development approach and is comprised of 26 million gross (22 million net) lateral feet in proven formations (Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones). Top of inventory range represents full development inventory in defined DSUs and is comprised of 35 million gross (30 million net) lateral feet in proven formations. 7

Setting a More Efficient Leading Edge 1,400 Recalibrating Operational Velocity Defend and Extend Efficiency Gains 2019 Action Plan targets increased footage drilled/completed per rig/crew over 2018 levels High-grade crews and equipment under reduced activity plan 1,200 12 high-spec AC rigs, all capable of drilling 2+ mile laterals Feet 1,000 800 600 400 1H17 2H17 1H18 2H18 Stimulated Lateral Feet per Operational Day per Crew Drilled Feet per Operational Day per Rig (1) (1) Lease Operating Expense ($/Boe) $5.50 $5.00 $4.50 $4.00 $3.50 $3.00 3-4 experienced, high-performing completions crews Bolster dedicated data analytics group Utilize technology and scale to maintain top-tier operating costs as well count grows Top-Tier Per-Unit LOE (2) Stringent cost control aided by water infrastructure and the sale of higher-cost vertical wells 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Parsley Energy Peer Average (1) Operational day measured as days equipment is active. Does not include mobilization or other idle time; (2) Public fillings. Peers include CDEV, CPE, CXO, FANG, JAG, LPI, and PXD. Includes impacts of ASC 606 in 2018. 8

Operational Spotlight Northern Midland County Plans for increased Northern Midland County development highlight cohesion of operating team and top-tier rock quality Ramping Northern Midland County Development Close collaboration and solid execution across multiple disciplines Showcases strong technical capability Recently drilled one of the longest laterals in the Permian in only 25 days Encouraging recent results from long lateral wells Three-well Massey pad completed with an upsized frac of 2,800 lbs/ft Midland Basin MARTIN HOWARD Producing ~1,900 Boe/d (82% oil) after 50+ days Efficient Long Lateral Development Lays Foundation For Success WINKLER ECTOR MIDLAND GLASSCOCK Feet - 2,000 4,000 6,000 8,000 10,000 12,000 Three-mile lateral drilled in less than 9 days Delaware Basin REEVES Lease Name Hogan WARD PECOS Central Basin Platform CRANE UPTON REAGAN Parsley Acreage Midland Focus Area Project Size Target Zone Productivity 3 Wells LS, WCA, and WCB Average IP30 of 1,480 Boe/d (81% oil) 14,000 16,000 0 1 2 3 4 5 6 7 8 9 10 Days Ranchland 6 Wells LS and WCB Massey 3 Wells LS, WCA, and WCB Average IP24 of 1,267 Boe/d (81% oil); has not reached peak 30-day rate Average IP24 of 1,949 Boe/d (81% oil); has not reached peak 30-day rate 9

Operational Spotlight Water Assets Proactive build-out of water infrastructure network with nearly $150 million of cumulative capital investment Saved $12 million on water sourcing, handling, and disposal costs in 4Q18 Permitted disposal capacity provides ample running room for future growth Robust Water Infrastructure Network Water Management Statistics Total Salt Water Disposal ( SWD ) Permitted Volume (Bbl/d) (1) Percent of Produced Water Transported by Pipeline Company-Wide 1.3 million 96% Surface Acres 38,000 1 2 3 4 Water A&D Activity Picking Up Date Buyer Seller Description 1/3/2019 12/20/2018 11/8/2018 10/31/2018 Private Company Private Company Western Gas Partners Private Company Concho Resources NGL Energy Partners Anadarko Petroleum Halcón Resources 100% interest in 3 SWDs with 44 miles of gathering pipeline in Southern Delaware 9 SWDs and associate pipelines along with additional permits in Southern Delaware 17 SWDs with 505 MBbls/d capacity and 620 miles of gathering pipelines in Delaware Basin All water facilities including gathering lines, SWDs, freshwater wells, and recycling facilities 2019 Action Plan Reduce water infrastructure capital expenditures YoY Increase revenue from third party water volumes 2 3 Delaware Basin REEVES Delaware Basin 1 WARD 4 3 4 PECOS 3 Midland Basin Midland Basin MARTIN MIDLAND HOWARD GLASSCOCK Review strategic alternatives Parsley Energy Acreage Parsley Energy SWD (1) UPTON REAGAN (1) Includes existing and permitted SWDs. 10

Guidance Summary Production 2018A 2019E Net Oil Production (MBo/d) 69.5 80.0-85.0 Net Production (MBoe/d) 109.4 124.0-134.0 Capital Program Total Development Expenditures ($MM) $1,762 $1,350 - $1,550 Drilling & Completion (% of Total) ~85% ~85% Facilities, Infrastructure & Other (% of Total) Activity ~15% ~15% Gross Operated Horizontal POPs (1) 175 130-140 Midland Basin (% of Total) ~75% ~85% Delaware Basin (% of Total) ~25% ~15% Average Lateral Length ~9,100' 10,000-10,500' Gross Operated Lateral Footage (000's) ~1,595' 1,350' - 1,470' Average Working Interest 97% ~90% 2019 Guidance Highlights Budgeting off of $50 WTI with priorities including: Meaningful progress toward sustainable free cash flow Outspend by less than $250 million in any commodity price environment 8-10%+ YoY improvement in capital efficiency (2) Preservation of operational efficiency gains at reduced activity level 12 high-spec rigs; 3-4 high-performing completions crews Disciplined organic oil growth ~20% YoY at midpoint (3) Units Costs Lease Operating Expenses ($/Boe) $3.61 $3.50 - $4.50 Cash G&A ($/Boe) $3.28 $2.75 - $3.25 Production & Ad Valorem Taxes (% of Total Revenue) 6% 6% - 7% 1Q19 Guidance Expect net 1Q19 oil production of 75.5-78.0 MBo/d (1) Wells placed on production; (2) Capital efficiency calculated as barrels of organic oil production added (Q4 1 /Q4 0, adjusted for PDP oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed in 4Q18; (3) Adjusted for divestitures closed in 2018. 11

Strong, Flexible Financial Position Liquidity ($MM) Cash on Hand Borrowing Base Availability Drawn on Revolver (%) $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 (2) Advantaged Liquidity Profile (1) PE Peer 1 Peer 2 Peer 3 Peer 4 21% 18% 15% 12% 9% 6% 3% 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 In 4Q18, Moody s upgraded Parsley s Corporate Family Rating to Ba3 from B1 Active hedge program helps protect cash flow and balance sheet while retaining oil price upside Peer-leading (1) liquidity of ~$1.2 billion (2) Remaining Borrowing Base $1,000 $1,100 $450 2H25 $700 Healthy leverage ratio of 1.5x (3) LTM Adj. 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 3Q18 filings and pro forma for subsequent debt offerings, acquisitions, and divestitures; (2) As of 12/31/2018; (3) Leverage ratio calculated as net debt at 12/31/2018 divided by last twelve-month Adjusted EBITDAX. Adjusted EBITDAX is a non-gaap financial measure. For a reconciliation of the non-gaap financial measure of adjusted EBITDAX to the most directly comparable GAAP financial measure, please see the Supplementary Slides. 12

Consistently Efficient Reserve Growth YE18 total proved reserves up 25% YoY (oil up 18% YoY) YE18 PD reserves up 49% YoY (oil up 43% YoY) Three-year proved reserve CAGR of 61% Organic reserves replacement ratio of 406% (1) Drillbit F&D (2) of $10.87/Boe displays quality and depth of asset base YE 2018 Proved Reserves Summary (5) Oil (MMBo) Gas (Bcf) NGL (MMBoe) Total (MMBoe) PDP 169.8 357.4 80.6 310.0 PNP 0.7 1.3 0.4 1.3 PUD 123.9 213.3 50.9 210.4 PD F&D of $11.63/Boe (3) supports top-tier recycle ratio of 2.6x (4) Total Proved 294.4 572.0 131.9 521.7 Strong Growth in Proved Reserves +25% 600 Proved Reserves (MMBoe) 500 400 300 200 222 416-40 +2-22 +6 +160 522 100 91 124 - YE14 YE15 YE16 YE17 Production Revisions Divestitures Acq. Additions YE18 (1) Organic reserves replacement ratio calculated as total 2018 reserve additions and revisions (technical and pricing) divided by total 2018 production. Excludes acquisitions and divestitures; (2) Drillbit F&D cost is calculated as total 2018 capital expenditures (including Infrastructure and Other) divided by total 2018 reserves additions and revisions (technical and pricing). Excludes acquisitions and divestitures; (3) Proved Developed F&D ( PD F&D ) cost is calculated as total 2018 capital expenditures (including Infrastructure and Other) divided by total 2018 proved developed reserves additions and revisions (technical and pricing). Excludes acquisitions and divestitures; (4) Recycle ratio calculated as 4Q18 Operating cash margin divided by PD F&D ($11.63/Boe). Oil and Gas PD F&D cost (excluding water handling infrastructure spend) was $11.29/Boe; (5) Reserve summary as of 12/31/2018 and audited by NSAI. 13

CLICK Supplementary TO ADD TEXT Slides SUPPLEMENTARY SUPPLEMENTARY SLIDES

Optimizing the 2019 Plan Transformational 2017 Simplified 2018 2019 Action Plan NPV-Focused ROR-Focused Agenda Achieve scale Recapture operational efficiency Boost capital efficiency by 8-10%+ and accelerate progress to self-funded growth Program Details Large rig ramp and delineation-heavy development program Steady development pace across geographically balanced program Reduce activity, increase proppant, highgrade development approach Spacing Pattern (Wells/Section/Bench) ~8-16 across ~8 across ~4-8 across MS JM Monitor peer results (Midland/Martin) Monitor peer results (Midland/Martin) LS Initial Parsley operated test (Upton) Increased proppant (Midland/Martin) Midland Basin Well Selection UWCA Initial test (Upton) WCA Test lower proppant loadings Increased proppant (All Counties) UWCB LWCB Stacked configuration (Upton/Reagan); 330 density tests (Reagan) Stacked configuration (Upton/Reagan) and lower proppant tests Stagger configuration (Upton/Reagan) and increased proppant WCC Initial success (Reagan) Delineation work (Reagan/Glasscock) Defer activity (low Waha prices) WCD Monitor peer results (Midland/Reagan) Delaware Basin Well Selection 3BS Initial test (Reeves) Monitor peer results UWCA Initial test (Pecos) Stagger configuration LWCA Increased proppant (Pecos) UWCB Initial test (Pecos) Monitor peer results Primary Development Focus Secondary Development Focus (1-2 wells) Future Development Potential 15

Hedge Position Open Crude Oil Derivatives Positions OPTION CONTRACTS CUSHING 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20 Hedging Strategy Put Spreads Cushing (MBbls/d) (1) 11.7 11.5 19.6 19.6 Long Put Price ($/Bbl) $51.43 $51.43 $59.79 $59.79 Short Put Price ($/Bbl) $44.29 $44.29 $49.79 $49.79 Three Way Collars - Cushing (MBbls/d) (2) 23.3 21.4 26.1 26.1 Short Call Price ($/Bbl) $70.48 $70.89 $72.69 $72.69 Long Put Price ($/Bbl) $48.21 $48.85 $51.88 $51.88 Short Put Price ($/Bbl) $40.71 $41.15 $42.81 $42.81 Collars Cushing (MBbls/d) (3) 3.3 24.7 21.2 21.2 Short Call Price ($/Bbl) $56.30 $57.67 $58.26 $58.37 Long Put Price ($/Bbl) $52.70 $53.94 $54.50 $54.56 MIDLAND Put Spreads Midland (MBbls/d) (1) 11.7 14.8 4.9 4.9 Long Put Price ($/Bbl) $50.71 $50.56 $60.00 $60.00 Short Put Price ($/Bbl) $40.71 $40.56 $50.00 $50.00 Three Way Colloars - Midland (MBbls/d) (2) 4.9 4.9 Short Call Price ($/Bbl) $64.65 $64.65 Long Put Price ($/Bbl) $50.00 $50.00 Short Put Price ($/Bbl) $45.00 $45.00 MAGELLAN EAST HOUSTON ("MEH") Put Spreads MEH (MBbls/d) (1) 3.3 3.3 8.2 8.2 5.0 4.9 Long Put Price ($/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 $60.00 Three Way Colloars - MEH (MBbls/d) (2) 3.3 3.3 Short Call Price ($/Bbl) $72.00 $72.00 Long Put Price ($/Bbl) $57.50 $57.50 Short Put Price ($/Bbl) $47.58 $47.58 Total Option Contracts (MBbls/d) 53.3 75.7 84.9 84.9 8.3 8.2 Premium Realization ($MM) (4) ($6.3) ($10.2) ($14.5) ($14.5) ($2.2) ($2.2) BASIS SWAPS Midland-Cushing Basis Swaps (MBbls/d) (5) 31.7 25.4 27.7 27.7 Swap Price ($/Bbl) ($7.51) ($5.10) ($1.74) ($0.91) MEH-Cushing Basis Swaps (MBbls/d) (5) 2.2 2.1 2.1 2.1 Swap Price ($/Bbl) $5.10 $5.10 $5.10 $5.10 Methodical, consistent approach Protect cash flow stream in weaker oil price environment Preserve meaningful upside exposure in stronger oil price environment Align hedges with regional price exposure Open Natural Gas Derivatives Positions OPTION CONTRACTS HENRY HUB 1Q19 2Q19 3Q19 4Q19 Three Way Collars - Henry Hub (MMBtu/d) (2) 33,333 32,967 32,609 32,609 Short Call Price ($/MMBtu) $3.93 $3.93 $3.93 $3.93 Long Put Price ($/MMBtu) $3.00 $3.00 $3.00 $3.00 Short Put Price ($/MMBtu) $2.50 $2.50 $2.50 $2.50 Total Option Contracts (MMBtu/d) 33,333 32,967 32,609 32,609 BASIS SWAPS Waha-Henry Hub Basis Swaps (MMBtu/d) (5) 28,889 32,967 32,609 32,609 Swap Price ($/MMBtu) ($1.84) ($1.92) ($1.78) ($1.64) Hedge positions as of 2/20/2019. Prices represent the weighted average price of contracts scheduled for settlement during the period; (1) When the reference price (WTI, Midland, MEH, or Henry Hub) 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. 16

Adjusted EBITDAX Reconciliation Unaudited, in thousands Three Months Ended December 31, Year Ended December 31, 2018 2017 2018 2017 Adjusted EBITDAX reconciliation to net income: Net income attributable to Parsley Energy, Inc. stockholders $53,773 $49,919 $369,127 $106,774 Net income (loss) attributable to noncontrolling interests 11,626 (4,922) 76,842 17,146 Depreciation, depletion and amortization 160,754 105,143 584,857 352,247 Exploration amd abandonment costs 142,622 35,122 162,539 39,345 Interest expense, net 32,880 32,402 131,460 97,381 Interest income (600) (2,374) (5,464) (7,936) Income tax expense (benefit) 16,453 (19,830) 105,475 5,708 EBITDAX $417,508 $195,460 $1,424,836 $610,665 Change in TRA liability 355 (56,396) 437 (35,847) Stock-based compensation 4,757 4,989 19,877 19,619 Acquisition costs 165 8 167 10,977 Accretion of asset retirement obligations 348 374 1,422 971 (Gain) loss on sale of property (16) 14,332 (6,454) 14,332 Loss on early extinguishment of debt - - - 3,891 Inventory write down - 1,060 495 1,060 (Gain) loss on derivatives (93,115) 72,310 (50,342) 66,135 Net settlements on derivative instruments 8,600 16 8,084 15,670 Net premiums on options that settled during the period (19,115) (14,699) (71,566) (37,103) Adjusted EBITDAX $319,487 $217,454 $1,326,956 $670,370 Note: Certain reclassifications to prior period amounts have been made to conform with current presentation. 17

Operating Cash Margin Reconciliation Unaudited, in thousands Three Months Ended December 31, Year Ended December 31, 2018 2017 2018 2017 Net income attributable to Parsley Energy, Inc. stockholders $53,773 $49,919 $369,127 $106,774 Net income (loss) attributable to noncontrolling interests 11,626 (4,922) 76,842 17,146 Income tax expense (benefit) 16,453 (19,830) 105,475 5,708 Other revenues (3,768) (1,517) (11,684) (5,050) Depreciation, depletion and amortization 160,754 105,143 584,857 352,247 Exploration and abandonment costs 142,622 35,122 162,539 39,345 Stock-based compensation 4,757 4,989 19,877 19,619 Acquisition costs 165 8 167 10,977 Accretion of asset retirement obligations 348 374 1,422 971 Other operating expenses 9,082 2,363 19,863 10,638 Interest expense, net 32,880 32,402 131,460 97,381 (Gain) loss on sale of property (16) 14,332 (6,454) 14,332 Prepayment premium on extinguishment of debt - - - 3,891 Derivative (gain) loss (93,115) 72,310 (50,342) 66,135 Change in TRA liability 355 (56,396) 437 (35,847) Interest income (600) (2,374) (5,464) (7,936) Other expense (income) 799 498 340 (783) Operating cash margin $336,115 $232,421 $1,398,462 $695,548 Operating cash margin per Boe $30.48 $31.45 $35.02 $28.06 Average price per Boe, without realized derivatives $40.91 $41.94 $45.44 $38.80 Operating cash margin percentage 75% 75% 77% 72% 18

Impact of ASC 606 Adoption 4Q18 Three Months Ended December 31, 2018 ASC 605 Adjustment ASC 606 Production revenues (in thousands): Oil sales $384,267 -- $384,267 Natural gas sales 6,843 1,919 8,762 Natural gas liquids sales 48,662 9,421 58,083 Total production revenues 439,772 11,340 451,112 Operating expenses Transportation and processing costs -- 11,340 11,340 Production revenues less transportation and processing costs $439,772 -- $439,772 Net income attributable to Parsley, Inc. stockholders (in thousands) $53,773 -- $53,773 Production: Oil (MBbls) 7,087 -- 7,087 Natural gas (MMcf) 8,432 1,264 9,696 Natural gas liquids (MBbls) 2,027 296 2,323 Total (MBoe) 10,519 507 11,026 Average daily production volume: Oil (Bbls) 77,033 -- 77,033 Natural gas (Mcf) 91,652 13,739 105,391 Natural gas liquids (Bbls) 22,033 3,217 25,250 Total (Boe) 114,337 5,511 119,848 Certain unit costs (per Boe): Lease operating expenses $3.78 ($0.17) $3.61 Transportation and processing costs -- $1.03 $1.03 Production and ad valorem taxes $2.49 ($0.11) $2.38 Depreciation, depletion and amortization $15.28 ($0.70) $14.58 General and administrative expenses (including stock-based compensation) $4.03 ($0.18) $3.85 General and administrative expenses (cash based) $3.58 ($0.16) $3.42 19

Impact of ASC 606 Adoption FY18 Year Ended December 31, 2018 ASC 605 Adjustment ASC 606 Production revenues (in thousands): Oil sales $1,536,244 -- $1,536,244 Natural gas sales 45,032 6,199 51,231 Natural gas liquids sales 200,898 26,374 227,272 Total production revenues 1,782,174 32,573 1,814,747 Operating expenses Transportation and processing costs -- 32,573 32,573 Production revenues less transportation and processing costs $1,782,174 -- $1,782,174 Net income attributable to Parsley, Inc. stockholders (in thousands) $369,127 -- $369,127 Production: Oil (MBbls) 25,356 -- 25,356 Natural gas (MMcf) 33,492 3,873 37,365 Natural gas liquids (MBbls) 7,356 997 8,353 Total (MBoe) 38,293 1,644 39,937 Average daily production volume: Oil (Bbls) 69,468 -- 69,468 Natural gas (Mcf) 91,759 10,611 102,370 Natural gas liquids (Bbls) 20,153 2,732 22,885 Total (Boe) 104,912 4,504 109,416 Certain unit costs (per Boe): Lease operating expenses $3.77 ($0.16) $3.61 Transportation and processing costs -- $0.82 $0.82 Production and ad valorem taxes $2.83 ($0.12) $2.71 Depreciation, depletion and amortization $15.27 ($0.63) $14.64 General and administrative expenses (including stock-based compensation) $3.94 ($0.16) $3.78 General and administrative expenses (cash based) $3.42 ($0.14) $3.28 20

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 12/31/2018 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on an unweighted first day of the month average 12-month WTI Phillips 66 posted price, net of differentials, of $61.88/Bbl for oil and $28.05/Bbl for NGLs and a WAHA spot natural gas price, net of differential, of $1.64/MMBtu for natural gas. References to our estimated proved reserves as of 12/31/2018 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 we identify. 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. Organic Reserves Replacement Ratio Parsley uses the organic reserves replacement ratio as an indicator of the Company's ability to replace the reserves that it has developed and to increase its reserves over time. The ratio is not a representation of value creation and has a number of limitations that should be considered. For example, the ratio does not incorporate the costs or timing of developing future reserves. The organic reserves replacement ratio is calculated as total reserve additions and revisions (technical and pricing), divided by total production. The ratio calculation excludes acquisitions and divestitures. 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 2018 capital expenditures (including Infrastructure and Other) divided by total 2018 proved developed reserves additions and revisions (technical and pricing). Drillbit F&D is calculated as total 2018 capital expenditures (including Infrastructure and Other), divided by total 2018 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 develop the company s reserves. Oil and gas PD F&D cost is 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. Recycle Ratio Parsley uses recycle ratio as a measure of its capital efficiency based on its finding and development costs. Recycle ratio is calculated as operating cash margin divided by all costs PD F&D. 21