INVESTOR PRESENTATION2Q 2018

2

Forward-Looking StatementsThe information in this presentation includes “forward-looking statements” that are made pursuant to the Safe Harbor Provisions of the Private Securities LitigationReform Act of 1995. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financialposition, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in thispresentation, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-lookingstatements, 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 tothe 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 aredifficult 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, environmentalrisks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, theproduction potential of our undeveloped acreage, cash flow and access to capital, the timing of development expenditures and the risk factors discussed in orreferenced in our filings with the United States Securities and Exchange Commission (“SEC”), including our Annual Report on Form 10-K and our subsequent QuarterlyReports 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 requiredby 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 reflectevents 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 existingwells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or cost increases.

Industry and Market DataThis presentation has been prepared by Parsley and includes market data and other statistical information from third-party sources, including independent industrypublications, government publications or other published independent sources. Although Parsley believes these third-party sources are reliable as of their respectivedates, Parsley has not independently verified the accuracy or completeness of this information. Some data are also based on Parsley’s good faith estimates, whichare 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 withParsley’s adoption of Accounting Standards Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”), effective January 1, 2018. Unless otherwisenoted, all references to 2Q18 production volumes and per Boe unit costs likewise reflect this adoption, which has the effect of increasing certain natural gas andNGLs volumes and revenues, offset by a corresponding transportation and processing cost such that there is no change to reported net income. The recognition andpresentation of oil volumes and associated revenues and expenses are unaffected by the adoption of ASC 606. For more information on ASC 606 and a reconciliationof 2Q18 production and unit costs under ASC 605 and as adjusted under ASC 606, please see slide 22.

Forward Looking Statements and Cautionary Statements

3

ANDREWS MARTIN

ECTOR

LEA

WINKLER

WARDCRANE

REEVES PECOS

UPTON

MIDLAND

GLASSCOCK

REAGAN

HOWARD

Parsley Energy Acreage(5)

DelawareBasin

CentralBasin

Platform

MidlandBasin

Generated company-record operating cash margin(1)

Compressed cycle times

Bolstered takeaway capacity

Posted peer-leading oil price realization

NYSE Symbol: PEMarket Cap: $9,937 MM(2)

Net Debt: $1,882 MM(3)

Enterprise Value: $11,819 MM(4)

Share Count: 317 MMPermian Basin Net Leasehold Acreage: ~210,000(5)

Midland Basin: ~164,000Delaware 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 dilutedshare 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 financialmeasure 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 marketcapitalization 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 bookvalue 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, andtherefore should not be added separately as a component of enterprise value; (5) As of 8/7/2018.

Premier Permian Pure-Play

2Q18 Highlights

4

-50%

-25%

0%

25%

50%

Peer

1 PE

Peer

2

Peer

3

Peer

4

Peer

5

Peer

6

Peer

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Peer

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Peer

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Peer

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Peer

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Peer

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Peer

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Peer

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Peer

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Peer

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Peer

24Co

mpo

und

Annu

al G

row

th R

ate

Production per DAS 2014-18E CAGR TSR CAGR from 6/30/2014

0

20

40

60

80

100

0 1 2 3 4 5 6 7 8 9 10 11 12 13

Net

Pro

duct

ion

(MBo

e/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) Parsleycompleted 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 frontmonth 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

5

Best-in-Class Reinvestment Runway

Parsley Energy AcreageParsley Operated Rigs(1)

HOWARD

GLASSCOCK

REAGAN

UPTON

MIDLAND

MARTIN

ANDREWS

ECTOR

CRANE

WARD

PECOS

REEVES

LOVINGWINKLER

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 offers 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 inLower 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 MiddleSpraberry, Cline, Atoka, 2nd Bone Spring and 3rd Bone Spring zones. Assumes no future trades or new organic leasing activity.

MidlandBasin

Central Basin Platform

DelawareBasin

6

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

30

40

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60

70

0

5

10

15

20

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18E 4Q18E

Net O

il Production (MBo/d)

Hor

izon

tal

Rig

Coun

t

Horizontal Rigs Quarterly Oil Production (MBo/d)

0

30

60

90

120

150

180

1Q18 2Q18 3Q18E 4Q18E

Cum

ulat

ive

Net

Ope

rate

d PO

Ps

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 working interest. 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

Dri

lled/

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plet

ed p

er D

ay p

er R

ig/C

rew

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 DoubleEagle acquisition announced on 2/7/2017.

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

MidlandBasin

HOWARD

ECTOR

UPTON

Parsley Energy AcreageAcreage Acquired via Trades or Acquisitions(2)

STERLING

IRION

8

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

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Gros

s Ope

rate

d O

il Vo

lum

e (B

o/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

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-$40

-$20

$0

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$80

1H18 2H18E 1H19E 2H19E 1H20E 2H20E

Market Im

plied Midland/G

ulf Coast D

ifferential ($/Bo)Pars

ley

Unh

edge

d O

il Pr

ice

Real

izat

ion

($/B

o)

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 realizedprice relative to Magellan East Houston (MEH) benchmark and excludes gathering fees; (4) Weighted average realization based on anticipated exposure to MEH, Cushing, and Midlandbenchmarks 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 pricingagreements; (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 on 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

Unh

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il Pr

ice

Real

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ion

($/B

o)

11

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 AcreageParsley Glasscock Pads (2016-Present)

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

Brunson pad

Parsley-record lateral of 12,225’

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Days on Production2016 20172018 Midland Basin Reference CurveBrunson WC-A Brunson WC-B

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ay per Rig

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w

Completed Feet per Day per Crew Drilled Feet per Day per Rig

12

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 directlycomparable GAAP financial measure, please see “Operating Cash Margin Reconciliation” in the Supplementary Slides. Operating cash margin percentage calculated as operating cash marginper 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 costsinclude 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 percentagereflects 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)

Ope

rati

ng C

ash

Mar

gin

Perc

enta

ge

Operating Cash Margin % Operating Costs ($/Boe)

2Q18: company-record cash margin

2Q18: company-low operating 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

Leas

e O

pera

ting

Exp

ense

($/

Boe)

Peers PE

Resumed downward trend after acquiring

several hundred vertical wells

Company-operated water management system, surface ownership, 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 of 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

`

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

14

0%

5%

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25%

$0

$300

$600

$900

$1,200

$1,500

PE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6

Percent Draw

n on Revolver

Liqu

idit

y ($

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-terminvestments. 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)

15

Investment Highlights

SUPPLEMENTARY SLIDES

15

16

$30

$35

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$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 O

il

Oil

Prod

ucti

on C

over

ed b

y Sw

aps

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 thelong 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 priceis 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 thereference 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 isbelow 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 receivesthe 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 averagereference 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 theperiod 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 ofsettlement; (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 24.5Long Put Price ($/Bbl) $49.64 $49.67 $54.17 $54.17 $58.83 $58.83Short Put Price ($/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 14.8Long Put Price ($/Bbl) $50.71 $50.56Short Put Price ($/Bbl) $40.71 $40.56

Mid-Cush Basis Swaps (MBbls/d)(4) 11.3 11.3 14.7 7.9Swap 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 15.0Swap 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-focusedE&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; operatingmargin is defined as realized price per Boe excluding hedges less per-unit lease operating expenses, transportation & gathering costs, total general & administrative expenses, production andad 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. PErecycle 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

0

50

100

150

200

250

300

350

400

450

YE14 YE15 YE16 Production Revisions Divestitures Acq. Additions YE17

Prov

ed R

eser

ves

(MM

Boe)

+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 andpricing); 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 2017proved developed reserves additions and revisions (technical and pricing); excludes acquisitions and divestitures. Refer to slide 23 for additional detail; (4) Recycle ratio calculated as 4Q17Operating 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 andGas 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%

0

100

200

300

400

500

0 1 2 3 4 5Years

% Oil of 3-Stream

Processed Volum

es

Gro

ss C

umul

ativ

e O

il Pr

oduc

tion

(M

Bo)

Midland Basin Reference Curve (Oil Only) Cumulative Oil %

50%

60%

70%

80%

90%

100%

0

100

200

300

400

500

0 1 2 3 4 5Years

% Oil of 3-Stream

Processed Volum

es

Gro

ss C

umul

ativ

e O

il Pr

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(M

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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 constitutesapproximately 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’sadoption of Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers (“ASC 606”), effective January 1, 2018; (2) Based on 9,500’ lateral. Excludesfacilities 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 assumesrealized 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

Payo

ut (

Year

s)

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

Payo

ut (

Year

s)

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 thousandsThree 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 thousandsThree 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, 2018ASC 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 57,275Total production revenues 459,364 6,471 465,835

Operating expensesTransportation and processing costs -- 6,471 6,471Production 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 -- 6,165Natural gas (MMcf) 8,287 948 9,235Natural gas liquids (MBbls) 1,853 253 2,106Total (MBoe) 9,399 412 9,811

Average daily production volume:Oil (Bbls) 67,747 -- 67,747Natural gas (Mcf) 91,066 10,418 101,484Natural gas liquids (Bbls) 20,363 2,780 23,143Total (Boe) 103,286 4,527 107,813

Certain unit costs (per Boe):Lease operating expenses $3.82 $(0.16) $3.66Transportation and processing costs -- $0.66 $0.66Production and ad valorem taxes $2.91 $(0.12) $2.79Depreciation, depletion and amortization $15.49 $(0.65) $14.84General and administrative expenses (including stock-based compensation) $3.83 $(0.16) $3.67General and administrative expenses (cash based) $3.26 $(0.14) $3.12

23

Reserves DisclosureOil & Gas ReservesThis 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 beestimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions (usingunweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right tooperate 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 SECpricing, 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 estimatedproved 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 meetthe 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. Unlessotherwise stated in this presentation, such estimates have been prepared internally by our engineers and management without review by independent engineers. Theseestimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of beingactually 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 thepotential for future drilling and production by the Company. Actual locations drilled and quantities that may be ultimately recovered from our properties will differsubstantially. In addition, we have made no commitment to drill all of the drilling locations. Ultimate recoveries will be dependent upon numerous factors including actualencountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets based upon ourfuture 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 fractionalinterest leases. Our estimates may change significantly as development of our properties provides additional data and therefore actual quantities that may ultimately berecovered will likely differ from these estimates. Our related expectations for future periods are dependent upon many assumptions, including estimates of productiondecline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may be affected by significant commodity price declines or drillingcost increases.

Unless otherwise noted, Net Present Value (“NPV”) estimates are before taxes and assume the Company generated EUR and decline curve estimates based on Companydrilling and completion cost estimates that do not include facilities, land, seismic, general and administrative (“G&A”) or other corporate level costs.

Organic Reserves Replacement RatioParsley 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”) CostsParsley 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.