INVESTOR PRESENTATION 2Q 2018 Forward Looking Statements and - - PowerPoint PPT Presentation

INVESTOR PRESENTATION 2Q 2018

2 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 June 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 2Q18 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

• f 2Q18 production and unit costs under ASC 605 and as adjusted under ASC 606, please see slide 22.

Forward Looking Statements and Cautionary Statements

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ANDREWS MARTIN ECTOR LEA WINKLER WARD CRANE REEVES PECOS UPTON MIDLAND GLASSCOCK REAGAN HOWARD

Parsley Energy Acreage(5)

Delaware Basin Central Basin Platform Midland Basin

• Generated company-record operating cash

margin(1)

• Compressed cycle times
• Bolstered takeaway capacity
• Posted peer-leading oil price realization

NYSE Symbol: PE Market Cap: $9,937 MM(2) Net Debt: $1,882 MM(3) Enterprise Value: $11,819 MM(4) Share Count: 317 MM Permian Basin Net Leasehold Acreage: ~210,000(5) Midland Basin: ~164,000 Delaware Basin: ~46,000 Permian Basin Net Royalty Acreage: ~7,000

• Superior acreage portfolio
• Advantaged marketing position
• Track record of efficient capital investment
• Efficient and sustainable growth profile
• Financial flexibility with strong balance sheet
• Minerals ownership provides economic uplift

Parsley Energy Overview

Market Snapshot Parsley Leasehold

(1) Operating cash margin is a non-GAAP financial measure. For reconciliation of operating cash margin to a GAAP financial measure, please see slide 21; (2) Calculated using fully diluted share count of 317 mm shares (280 mm Class A shares plus 37 mm Class B shares) as of 8/7/2018 and closing price as of 8/6/2018; (3) As of 6/30/2018. Net Debt is a non-GAAP financial measure that is defined as total debt less cash and cash equivalents and short-term investments; (4) 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 therefore should not be added separately as a component of enterprise value; (5) As of 8/7/2018.

Premier Permian Pure-Play 2Q18 Highlights

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• 50%
• 25%

0% 25% 50% Peer 1 PE Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19 Peer 20 Peer 21 Peer 22 Peer 23 Peer 24 Compound Annual Growth Rate Production per DAS 2014-18E CAGR TSR CAGR from 6/30/2014 20 40 60 80 100 1 2 3 4 5 6 7 8 9 10 11 12 13 Net Production (MBoe/d) Years

Peer-Leading Production Growth Translated to Significant Value Creation

Achieving Scale in Record Time

(1) Bloomberg; Peers include all oil-focused E&Ps (oil represents at least 40% of reported 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) Parsley completed its initial public offering on 5/29/2014; (3) Evercore ISI; Peers include APA, APC, AR, CHK, CLR, COG, CPE, CXO, DVN, ECA, EGN, EOG, FANG, MRO, NBL, NFX, OAS, PXD, QEP, RRC, SWN, WLL, WPX, and XEC; (4) FactSet; Total shareholder return (TSR) calculated as (End Price – Beginning Price + Dividends) / Beginning Price. Priced as of 7/31/2018; (5) FactSet; WTI front month price as of 7/30/2018 compared to 6/30/2014.

Fastest to 100 MBoe/d

Volume growth has accrued to shareholders, as evidenced by:

• Superior production growth per debt-adjusted share(3)
• Positive total shareholder return (TSR)(4) despite 35%

decline in oil prices(5)

• No oil-focused E&P has grown production from 10 to 100

MBoe/d faster than Parsley Energy(1)

• 16% compound quarterly production growth rate since

IPO,(2) with minimal contribution from acquired volumes

Parsley

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Best-in-Class Reinvestment Runway

Parsley Energy Acreage Parsley Operated Rigs(1) HOWARD GLASSCOCK REAGAN UPTON MIDLAND MARTIN ANDREWS ECTOR CRANE WARD PECOS REEVES LOVING WINKLER STERLING IRION

• Durable, high quality inventory

yields long reinvestment runway

• Robust production trend on

geographically balanced activity profile implies sustainably strong growth trajectory

• Over 6,000 gross operated

development locations in proven formations(2)

• Over a decade of operated

development inventory life(2) in each distinct core geography

• Delineation inventory(3) comprising

almost 4,000 identified locations

• ffers substantial resource upside

% of Dev Inventory Drilled % of Dev Inventory Remaining Inventory Life at Current Pace

(1) Excludes surface and service rigs. Rig distribution based on average 2Q18 activity levels operating in each development area; (2) Development inventory includes operated locations in Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones. Assumes no future trades or new organic leasing activity; (3) Delineation inventory includes operated locations in Middle Spraberry, Cline, Atoka, 2nd Bone Spring and 3rd Bone Spring zones. Assumes no future trades or new organic leasing activity.

Midland Basin Central Basin Platform Delaware Basin

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Delivering more net wells and higher oil production with efficient development program

30 40 50 60 70 5 10 15 20 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18E 4Q18E Net Oil Production (MBo/d) Horizontal Rig Count Horizontal Rigs Quarterly Oil Production (MBo/d) 30 60 90 120 150 180 1Q18 2Q18 3Q18E 4Q18E Cumulative Net Operated POPs Actual New Guidance Previous Guidance

Executing Across the Business

(1) Operated horizontal wells placed on production; (2) Based on revised guidance for 2018 gross POPs and mid-point of revised guidance for 2018 average workinginterest. See slide 13 for details.

Strong Production Trend on Steady Rig Count Net POPs Trending Higher More Gross POPs(1)

FY18 POP guidance increasing by 14 net wells(2)

Higher Working Interest

Updated 2018E Production Guidance (68.0-70.5 MBo/d) Previous 2018E Production Guidance (65.0-70.0 MBo/d)

Healthy Cycle Times Development Execution Accretive Acreage Trades and Partner Buy-outs Asset Execution

7 200 400 600 800 1,000 1,200 2Q17 3Q17 4Q17 1Q18 2Q18 Feet Drilled/Completed per Day per Rig/Crew Midland Basin Completed Feet per Day per Crew Midland Basin Drilled Feet per Day per Rig

Development Execution - Positive Efficiency Trends

Operational Momentum on Optimized Footprint

Asset Execution – Solidifying the Core Full recovery of operational efficiency following acquisition integration and associated rig ramp

Double Eagle acquisition closed April 2017

(1) Acreage received in trades is net of assets traded away. Equivalent acreage based on net drilling inventory added assuming 32 7,500' wells per 960-acre DSU; (2) Acquired since Double Eagle acquisition announced on 2/7/2017.

Trades, bolt-ons, and buy-outs block up core

• perated footprint, enhancing capital efficiency

through:

• Longer laterals
• Shared infrastructure and facilities
• Higher working interest

Added equivalent of more than 20,000(1) net acres during past 18 months, primarily through acreage trades with no financial outlay

ANDREWS MARTIN MIDLAND GLASSCOCK REAGAN

Midland Basin

HOWARD ECTOR UPTON

Parsley Energy Acreage Acreage Acquired via Trades or Acquisitions(2)

STERLING IRION

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Diversified pricing and staggered contract expirations translate to healthy realizations and favorable negotiation windows

Foundations of Advantaged Marketing Position

Proactive marketing strategy has put Parsley in position of strength

Early-Mover Gathering Contracts Attractive Barrel Robust Historical and Projected Volume Growth Flexible Connection and Terminus Favorable Oil Quality and Consistency Advantaged Takeaway

Ample takeaway capacity and unrestrictive volume commitments preserve development flexibility

Flow Assurance Robust Realizations

Medallion & NuStar Gathering Systems Parsley Energy Acreage

9 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000

Gross Operated Oil Volume (Bo/d)

Firm Transportation with Minimum Volume Commitments (MVCs) Firm Transportation without MVCs

(2) (2)

Incremental Flow Assurance

(1) Incremental agreements include executed contracts and one letter of intent that outlines commercial terms but has not been contractualized; (2) Estimated takeaway capacity contingent on pipeline start-up dates, assumptions for which are based on most recent public disclosures.

Marketing strategy centered around two guiding principles: dependability and diversification

• Legacy transportation agreements secured foundational takeaway capacity of 95 MBo/d
• Incremental agreements, if all are completed, expected to increase deliverability to approximately 165 MBo/d during

anticipated Permian tightness, ensuring ample growth capacity(1)

• Low volume commitments relative to guaranteed delivery limit deficiency exposure
• Expected tenure of takeaway contract portfolio would afford opportunity to capitalize on favorable infrastructure

dynamics when tightness subsides

Legacy takeaway deals provide advantaged starting position

Security of Flow Assurance Improves Growth Visibility

New marketing agreements would bolster ample takeaway runway and support growth plans Opportunity to expand capacity in oversupplied takeaway market 2H17 1H18 2H18E 1H19E 2H19E 1H20E 2H20E 1H21E 2H21E

10

• $20
• $10

$0 $10 $20 $30 $40

• $40
• $20

$0 $20 $40 $60 $80 1H18 2H18E 1H19E 2H19E 1H20E 2H20E Market Implied Midland/Gulf Coast Differential ($/Bo) Parsley Unhedged Oil Price Realization ($/Bo) PE Unhedged Oil Price Realization (Net of Gathering Fee) Midland/Gulf Coast Forward Differential

Pricing Insulation

(1) Company filings; PE realized oil 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) Based on executed firm transport contracts and one letter of intent that outlines commercial terms but has not been contractualized; (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 7/30/2018; net of gathering fee at assumed $1.25/Bbl; 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 7/30/2018.

• Proactive oil price diversification translated to peer-

leading realizations during 2Q18

• Ongoing exposure to Gulf Coast pricing insulates from

Midland differentials and translates to healthy projected realizations during infrastructure buildout

• Early-mover advantages on 2019 takeaway facilitated

favorable pricing on longer-term agreements

• Expect ~$2/Bbl differential to Gulf Coast price
• n barrels covered by firm transport in

2020(2)(3)

• Additional diversification through exposure to

international pricing(2)

Marketing strategy centered around two guiding principles: dependability and diversification

Expect consistently strong realizations even during period of relative Midland price weakness

(2)(4) (5)

Leading Oil Price Realization(1) Historical & Illustrative Oil Price Realizations

$56 $57 $58 $59 $60 $61 $62 $63 $64 $65

PE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9

2Q18 Unhedged Oil Price Realization ($/Bo)

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Operational Spotlight – Glasscock County

• Growing portfolio of well results across Glasscock acreage

confirms Glasscock County asset quality

• 2Q18 completion activity weighted toward Glasscock County,

with 14 wells placed on production, including:

• One well with Parsley-record lateral length of more than

12,000’

• Two wells representing most prolific Parsley Wolfcamp A/B

stack in Glasscock, with average IP30/1,000’ of 177 Boe/d (84% oil)

• Development experience across Glasscock footprint translating to

enhanced operational efficiency Glasscock Wolfcamp A & B Wells Outperforming Midland Basin Reference Curve(1) Expanding Glasscock Development Favorable Glasscock Operational Efficiency Trends

GLASSCOCK STERLING

Parsley Energy Acreage Parsley Glasscock Pads (2016-Present)

(1) Normalized to 10,000’ lateral; adjusted for downtime.

Brunson pad Parsley-record lateral of 12,225’

50 100 150

30 60 90 120 150 180

Cumulative Oil Production (MBo) Days on Production

2016 2017 2018 Midland Basin Reference Curve Brunson WC-A Brunson WC-B 200 400 600 800 1,000 300 600 900 1,200 1,500 2016 2017 1H18 Drilled Feet per Day per Rig Completed Feet per Day per Crew Completed Feet per Day per Crew Drilled Feet per Day per Rig

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Retaining almost 80% of robust realized price as marketing advantages, operating cost compression, and scale benefits flow through Company-Record Operating Cash Margin Percentage(1)

Extracting More Value per Barrel

(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 comparison purposes, per-unit operating cost trend excludes transportation and process costs. 1Q18 and 2Q18 operating cash margin percentage reflects adoption of ASC 606; (2) Company filings; Peers include CPE, CXO, EGN, FANG, LPI, and PXD. PE LOE in 1Q18 and 2Q18 reflects adoption of ASC 606.

$8 $12 $16 $20 $24 $28 $32 20% 30% 40% 50% 60% 70% 80% 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Operating Costs ($/Boe) Operating Cash Margin Percentage Operating Cash Margin % Operating Costs ($/Boe) 2Q18: company- record cash margin 2Q18: company-low

• perating cost per Boe

Peer-leading LOE Trend(2)

$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 $6.50 $7.00 $7.50 $8.00 $8.50 2Q16 3Q16 4Q16 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 Lease Operating Expense ($/Boe) Peers PE Resumed downward trend after acquiring several hundred vertical wells

Company-operated water management system, surface

• wnership, electrical substation build-out, and downtime

minimization efforts support peer-leading LOE per BOE

13

Production 2018E (Prior) 2018E (Updated) Annual Net Oil Production (MBo/d) 65 - 70 68.0 - 70.5 Annual Net Production (MBoe/d)(1) 98 - 108 106 - 111 Capital Program Total Development Expenditures ($MM) $1,350 - $1,550 $1,650 - $1,750 Drilling & Completion (% of Total) 85 – 90% 85 – 90% Facilities, Infrastructure & Other (% of Total) 10 – 15% 10 – 15% Activity Gross Operated Horizontal POPs(2) ~160 ~165 Midland Basin (% of Total) ~75% ~75% Delaware Basin (% of Total) ~25% ~25% Average Lateral Length ~9,500’ ~9,500’ Average Working Interest ~90% 95 – 97% Net Operated Horizontal POPs(2) ~144 157 - 160 Units Costs Lease Operating Expenses ($/Boe)(1) $3.75 - $5.00 $3.50 - $4.25 Cash G&A ($/Boe)(1) $3.50 - $4.25 $3.25 - $3.65 Production & Ad Valorem Taxes (% of Revenue) 6.0 – 7.0% 6.0 – 7.0%

(1) Incorporates adoption of ASC 606; (2) Wells placed on production; (3) D&C costs based on 9,500’ average lateral length.

• Strong execution on simplified development

program translates to more net POPs, driving higher production and capex

• Favorable efficiency trends enable

transition back to larger average pad size, with larger projects folded in over back half

• f the year
• Significant reductions in unit cost guidance

support healthy margins

Updated Guidance Summary

Midland Basin Delaware Basin $8.4 - $8.8 $11.5 - $12.0 ~$8.8 ~$12.0 2018E Well Costs ($MM)(3) 2018 Guidance Highlights

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Steel tariffs and labor tightness have pushed per well costs to top of range

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0% 5% 10% 15% 20% 25% $0 $300 $600 $900 $1,200 $1,500 PE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Percent Drawn on Revolver Liquidity ($MM)

Cash on Hand Borrowing Base Availability Drawn on Revolver (%)

$1,000 $1,300 $400 $650 $700 $450

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Revolving Credit Facility ($MM) Senior Notes ($MM)

Advantaged Liquidity Profile(1)

• Peer-leading(1) liquidity of $1.3 billion(2) provides ample flexibility to

fund efficient growth

• Favorable debt maturity schedule with earliest notes maturity in 2024
• Weighted average cost of debt has dropped ~230 bps over last two years

Strong, Flexible Financial Position

Favorable Debt Maturity Schedule

Committed Amount Remaining Borrowing Base

1H25 2H25

(1) Permian SMID-Cap peers include CDEV, CPE, EGN, FANG, JAG, and LPI. Calculated as availability on committed portion of borrowing base plus cash and cash equivalents and short-term

• investments. Peer data obtained from 1Q18 filings and pro forma for subsequent debt offerings and divestitures; (2) As of 6/30/2018.

$1,100 $2,300

(2)

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Investment Highlights SUPPLEMENTARY SLIDES

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16

$30 $35 $40 $45 $50 $55 $60 $65 $70 0% 10% 20% 30% 40% 50% 60% 70% 80% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 PE Dollar per Barrel of Oil Oil Production Covered by Swaps 2H18E Swap Coverage (Left Axis) 2019E Swap Coverage (Left Axis) 2H18E Swap Price (Right Axis) 2019E Swap Price (Right Axis) 2H18 WTI Strip (Right Axis) 2019 WTI Strip (Right Axis)

Oil Hedge Position

Hedge positions as of 8/7/2018. Prices represent the weighted average price of contracts scheduled for settlement during the period; (1) When the reference price (WTI or Midland) 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) Parsley receives the swap price; (5) 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; (6) Premium realizations represent net premiums paid (including deferred premiums), which are recognized as a loss in the period of settlement; (7) BMO Capital Markets; Peers include CPE, CXO, FANG, JAG, LPI, and REN. WTI strip from FactSet as of 7/30/2018.

3Q18 4Q18 1Q19 2Q19 3Q19 4Q19 Put Spreads – WTI (MBbls/d)(1) 34.2 37.5 20.0 19.8 24.5 24.5 Long Put Price ($/Bbl) $49.64 $49.67 $54.17 $54.17 $58.83 $58.83 Short Put Price ($/Bbl) $39.64 $39.67 $44.17 $44.17 $48.83 $48.83 Three Way Collars - WTI (MBbls/d)(2) 31.0 31.0 8.3 8.2 9.8 9.8 Short Call Price ($/Bbl) $75.65 $75.65 $80.40 $80.40 $80.33 $80.33 Long Put Price ($/Bbl) $50.00 $50.00 $50.00 $50.00 $50.83 $50.83 Short Put Price ($/Bbl) $40.00 $40.00 $40.00 $40.00 $40.83 $40.83 Collars – WTI (MBbls/d)(3) 3.0 3.0 Short Call Price ($/Bbl) $61.31 $61.31 Long Put Price ($/Bbl) $45.67 $45.67 MBbls/d Hedged – WTI 68.2 71.5 28.3 28.0 34.2 34.2 Put Spreads – Midland (MBbls/d)(1) 11.7 14.8 Long Put Price ($/Bbl) $50.71 $50.56 Short Put Price ($/Bbl) $40.71 $40.56 Mid-Cush Basis Swaps (MBbls/d)(4) 11.3 11.3 14.7 7.9 Swap Price ($/Bbl) ($0.86) ($0.86) ($8.95) ($9.08) MBbls/d Hedged – Midland 11.3 11.3 26.4 22.7 Rollfactor Swaps (MBbls/d)(5) 15.0 15.0 Swap Price ($/Bbl) $0.60 $0.60 Premium Realization ($MM)(6) ($17.9) ($19.1) ($11.6) ($12.5) ($9.8) ($9.8)

Crude Realizations Not Constrained by Swaps(7)

Hedge structure retains upside to higher oil prices

Open Crude Oil Derivatives Positions

17 Oil-focused E&P Companies 0.0 1.0 2.0 3.0 4.0 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45

Top-Tier Capital Efficiency

Source: SGS E&P Comp Sheets – week ending July 27, 2018. Companies include APA, APC, AR, AREX, AXAS, CDEV, CHK, CLR, CNX, COG, CPE, CRC, CRK, CRZO, CXO, DNR, DVN, ECA, ECR, EGN, EOG, EPE, EQT, ESTE, FANG, GDP, GPOR, GST, HES, HPR, JAG, JONE, LPI, MCF, MRO, MTDR, MUR, NBL, NFX, NOG, OAS, OXY, PDCE, PE, PXD, QEP, REI, REN, RRC, SBOW, SD, SM, SN, SRCI, SWN, UPL, WLL, WPX, WRD, WTI, XEC, and XOG; Oil-focused E&P Companies are defined as companies with oil accounting for 40% or more of 2017 production, and gas-focused E&P Companies are defined as companies with oil accounting for less than 40% of 2017 production. (1) 1Q18 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; (2) Recycle ratio is equal to operating margin divided by PD F&D. F&D costs based on 2017 data and operating margin based on 1Q18. PE recycle ratio includes actual 2017 PD F&D/Boe of $12.10.

• Strong capital efficiency driven by combination of healthy operating

margins and low finding costs

• Superior capital efficiency indicates production growth creates value

Recycle Ratio(2)

Parsley Energy

Operating Margin ($/Boe)(1)

Parsley Energy Gas-focused E&P Companies Oil-focused E&P Companies Gas-focused E&P Companies

18

91 416

• 25
• 6

+ 9 +56 +160 50 100 150 200 250 300 350 400 450

YE14 YE15 YE16 Production Revisions Divestitures Acq. Additions YE17

Proved Reserves (MMBoe) +87%

(1) Organic reserves replacement ratio calculated as total 2017 reserve additions and revisions (technical and pricing) divided by total 2017 production; excludes acquisitions and divestitures. For additional detail refer to slide 23; (2) Drillbit F&D calculated as total 2017 Capex (including infrastructure and Other) divided by total 2017 reserves additions and revisions (technical and pricing); excludes acquisitions and divestitures. For additional detail refer to slide 23; (3) PD F&D calculated as total 2017 Capex (including Infrastructure and Other) divided by total 2017 proved developed reserves additions and revisions (technical and pricing); excludes acquisitions and divestitures. Refer to slide 23 for additional detail; (4) Recycle ratio calculated as 4Q17 Operating cash margin divided by PD F&D ($12.10/Boe); oil and gas PD F&D cost (includes only development capital) was $11.61/Boe; Refer to slide 23 for definitions of PD F&D and Oil and Gas PD F&D costs; (5) Reserve summary as of 12/31/2017 and audited by NSAI.

Consistently Efficient Reserve Growth

• YE17 proved reserves up 87% Y/Y (oil up 82% Y/Y)
• Three-year proved reserve CAGR of 66%
• Organic reserves replacement ratio of 683%(1)
• Positive performance revisions of 4.5 MMBo to oil PDP reserves highlight stability of asset base
• Drillbit F&D(2) of $7.12/Boe displays quality and depth of asset base
• PD F&D of $12.10/Boe(3) during delineation heavy year supports top-tier recycle ratio of 2.6x(4)

124

Strong Growth in Proved Reserves

Oil (MMBbl) Gas (Bcf) NGL (MMBbl) Total (MMBoe) PDP 118.5 237.2 49.1 207.2 PDNP 1.1 3.1 0.6 2.2 PUD 128.9 211.4 42.9 207.0

Total Proved 248.5 451.7 92.6 416.4

Proved Reserves Summary(5)

222

19 50% 60% 70% 80% 90% 100% 100 200 300 400 500 1 2 3 4 5 Years % Oil of 3-Stream Processed Volumes Gross Cumulative Oil Production (MBo) Midland Basin Reference Curve (Oil Only) Cumulative Oil % 50% 60% 70% 80% 90% 100% 100 200 300 400 500 1 2 3 4 5 Years % Oil of 3-Stream Processed Volumes Gross Cumulative Oil Production (MBo)

• S. Delaware Basin Reference Curve (Oil Only)

Cumulative Oil %

Reference Curves Imply Compelling Economics

(1) Based on 10,000’ lateral. Gross oil and processed NGL and gas volumes are not adjusted for various loss and downtime factors—the combination of which typically constitutes approximately 10% of gross or processed volumes—and are presented before the application of working interest and royalty interest; Oil mix reflects adjustments associated with Parsley’s adoption of Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”), effective January 1, 2018; (2) Based on 9,500’ lateral. Excludes facilities costs and assumes realized gas price of $2.50/MMBtu, realized NGL price of 40% WTI, and 25% royalty burden; (3) Based on 9,500’ lateral. Excludes facilities costs and assumes realized gas price of $2.50/MMBtu, realized NGL price of 40% WTI, and 15% royalty burden.

`

Estimated Midland Basin Well Payout Period(2) Estimated Delaware Basin Well Payout Period(3) Midland Basin Oil Curve(1) Delaware Basin Oil Curve(1)

0.5 1.0 1.5 2.0 2.5 3.0 $40 $45 $50 $55 $60 $65 $70 Payout (Years) Realized Oil Price ($/Bbl) $12.0 MM Drilling & Completion Cost per Well 0.5 1.0 1.5 2.0 2.5 $40 $45 $50 $55 $60 $65 $70 Payout (Years) Realized Oil Price ($/Bbl) $8.8 MM Drilling & Completion Cost per Well

20

Adjusted EBITDAX Reconciliation

Note: Certain reclassifications to prior period amounts have been made to conform with current presentation.

Unaudited, in thousands Three Months Ended June 30, Six Months Ended June 30, Adjusted EBITDAX reconciliation to net income: 2018 2017 2018 2017 Net income attributable to Parsley Energy, Inc. stockholders $119,155 $40,746 $202,045 $70,188 Net income attributable to noncontrolling interests 21,803 15,048 44,376 23,896 Depreciation, depletion and amortization 145,552 83,315 266,751 152,285 Exploration and abandonment costs 3,366 2,442 8,777 5,205 Interest expense, net 33,758 22,764 65,726 42,100 Interest income (1,686) (2,178) (3,809) (4,549) Income tax expense 33,243 12,216 56,568 30,618 EBITDAX 355,191 174,353 640,434 319,743 Change in TRA liability

• 82

20,549 Stock-based compensation 5,363 5,251 10,432 9,460 Acquisition costs (2) 7,176 2 8,520 Gain on sale of property (5,166)

• (5,055)
• Accretion of asset retirement obligations

359 193 713 329 Loss on early extinguishment of debt

• 3,891

Inventory write down (17)

• 44
• Loss (gain) on derivatives

9,466 (43,514) 20,259 (68,130) Net settlements on derivative instruments (7,019) 4,973 (9,892) 4,672 Net premiums on options that settled during the period (18,072) (5,063) (34,598) (9,917) Adjusted EBITDAX $340,103 $143,369 $622,421 $289,117

21

Operating Cash Margin Reconciliation

$ in thousands Three Months Ended June 30, Six Months Ended June 30, 2018 2017 2018 2017 Net income attributable to Parsley Energy, Inc. stockholders $119,155 $40,746 $202,045 $70,188 Net income attributable to noncontrolling interests 21,803 15,048 44,376 23,896 Income tax expense 33,243 12,216 56,568 30,618 Other revenues (1,953) (2,292) (5,547) (3,525) Depreciation, depletion and amortization 145,552 83,315 266,751 152,285 Exploration and abandonment costs 3,366 2,442 8,777 5,205 Stock-based compensation 5,363 5,251 10,432 9,460 Acquisition costs (2) 7,176 2 8,520 Accretion of asset retirement obligations 359 193 713 329 Other operating expenses 2,477 2,503 4,652 4,786 Interest expense, net 33,758 22,764 65,726 42,100 Gain on sale of property (5,166)

• (5,055)
• Prepayment premium on extinguishment of debt
• 3,891

Derivative income (loss) 9,466 (43,514) 20,259 (68,130) Change in TRA liability

• 82

20,549 Interest income (1,686) (2,178) (3,809) (4,549) Other income (expense) (234) 177 (535) (773) Operating cash margin $365,501 $143,847 $665,437 $294,850 Operating cash margin per Boe $37.25 $24.42 $36.52 $27.25 Average price per Boe, without realized derivatives $47.48 $35.89 $46.92 $37.98 Operating cash margin percentage 78% 68% 78% 72%

22

Impact of ASC 606 Adoption

Three Months Ended June 30, 2018 ASC 605 Adjustment ASC 606 Production revenues (in thousands): Oil sales $396,325

• $396,325

Natural gas sales 11,094 1,141 12,235 Natural gas liquids sales 51,945 5,330 57,275 Total production revenues 459,364 6,471 465,835 Operating expenses Transportation and processing costs

• 6,471

6,471 Production revenues less transportation and processing costs $459,364

• $459,364

Net income attributable to Parsley, Inc. stockholders (in thousands) $119,155

• $119,155

Production: Oil (MBbls) 6,165

• 6,165

Natural gas (MMcf) 8,287 948 9,235 Natural gas liquids (MBbls) 1,853 253 2,106 Total (MBoe) 9,399 412 9,811 Average daily production volume: Oil (Bbls) 67,747

• 67,747

Natural gas (Mcf) 91,066 10,418 101,484 Natural gas liquids (Bbls) 20,363 2,780 23,143 Total (Boe) 103,286 4,527 107,813 Certain unit costs (per Boe): Lease operating expenses $3.82 $(0.16) $3.66 Transportation and processing costs

• $0.66

$0.66 Production and ad valorem taxes $2.91 $(0.12) $2.79 Depreciation, depletion and amortization $15.49 $(0.65) $14.84 General and administrative expenses (including stock-based compensation) $3.83 $(0.16) $3.67 General and administrative expenses (cash based) $3.26 $(0.14) $3.12

23

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

• perate 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

• therwise 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. 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 of 683% was calculated as total 2017 reserve additions and revisions (technical and pricing), divided by total 2017 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 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.