PARSLEYENERGY.COM

INVESTOR PRESENTATION3Q »2017

Q3 2018Earnings Presentation

November 1, 2018

2

Forward Looking & Cautionary Statements

Forward-Looking StatementsThe information in this presentation includes “forward-looking statements” that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation ReformAct of 1995. All statements, other than statements of historical fact included in this presentation, regarding our strategy, future operations, financial position, estimatedrevenues 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-lookingstatements contain such identifying words. These forward-looking statements are based on Parsley Energy, Inc.’s (“Parsley Energy,” “Parsley,” or the “Company”) currentexpectations 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 theseforward-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 theexploration 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 ofavailability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent inestimating reserves and in projecting future rates of production, the production potential of our undeveloped acreage, cash flow and access to capital, the timing ofdevelopment expenditures and the risk factors discussed in or referenced in our filings with the United States Securities and Exchange Commission (“SEC”), including ourAnnual 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 byapplicable 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 orcircumstances 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 andthe 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 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 derivedfrom its review of internal sources as well as the third-party sources described above.

Accounting Standards Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”)Natural gas and natural gas liquids (“NGLs”) sales and associated production volumes for the three months ended September 30, 2018 reflect adjustments associated 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 3Q18 production volumes and per Boe unit costs likewise reflect this adoption, which has the effect of increasing certain natural gas and NGLsvolumes and revenues, offset by a corresponding transportation and processing cost such that there is no change to reported net income. The recognition and presentationof oil volumes and associated revenues and expenses are unaffected by the adoption of ASC 606. For more information on ASC 606 and a reconciliation of 3Q18 productionand unit costs under ASC 605 and as adjusted under ASC 606, please see Supplementary Slides.

3

Parsley Energy Overview

► Robust operating cash margin(1)

► Disciplined portfolio management

► Sustained operational momentum

► Reduced capital costs

► Efficient and sustainable growth trend

► Elite return profile

► Economies of scale and core inventory depth

► Advantaged production flow and pricing

► Financial flexibility with strong balance sheet

► Economic uplift from minerals ownership

ANDREWS

MARTIN

ECTOR

LEA

WINKLER

WARD

CRANE

REEVESPECOS

UPTON

MIDLAND

GLASSCOCK

REAGAN

HOWARD

DelawareBasin

CentralBasin

Platform

MidlandBasin

(1) Operating cash margin is a non-GAAP financial measure. For reconciliation of operating cash margin to the most directly comparable GAAP financial measure, please see Supplementary Slides; (2) As of 11/1/2018 pro forma forpending divestiture; (3) Calculated using fully diluted share count of 317 mm shares (280mm Class A shares plus 37mm Class B shares) as of 11/1/2018 and closing price as of 10/31/2018; (4) As of 9/30/2018 pro forma for expectedproceeds of ~$165 million from divestitures announced 11/1/2018. Net Debt is a non-GAAP financial measure defined as total debt less cash and cash equivalents; (5) Enterprise value is calculated as market capitalization plus netdebt, 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 allocatedto 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.

Premier Permian Pure-Play

3Q18 Highlights

NYSE Symbol: PEMarket Cap: $7,419 MM(3)

Net Debt: $1,851 MM(4)

Enterprise Value: $9,270 MM(5)

Share Count: 317 MM

Market Snapshot

Permian Basin Net Net Leasehold Acreage: ~200,000(2)

(96% Operated)Midland Basin: ~155,000Delaware Basin: ~45,000

Net Royalty Acreage: ~7,500

Parsley Energy Acreage

Parsley Acreage

-50%

-25%

0%

25%

50%

Com

poun

d An

nual

G

row

th R

ate

Production per DAS 2014-18E CAGR TSR CAGR from PE IPO

0

25

50

75

100

125

0

4

8

12

16

20

1Q14

2Q14

3Q14

4Q14

1Q15

2Q15

3Q15

4Q15

1Q16

2Q16

3Q16

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

Net P

roduction (MB

oe/d)Hor

izon

tal R

ig C

ount

Horizontal Rigs Net Production (MBoe/d)

Parsley Operating Area in 2008Parsley Acreage

Build Reinvestment RunwayAchieve Scale

4

Laying the Foundation – 10-Year Lookback

(1) Bloomberg; Based on number of reporting periods for production between 10 MBoe/d and 100 MBoe/d; Peers include oil-focused E&Ps (oil represents at least 40% of total production) for which relevant production data is available;Peers include AREX, BCEI, CDEV, CLR, CPE, CRZO, CXO, FANG, HK, JAG, MTDR, NOG, OAS, PDCE, PetroHawk, ROSE, RSPP, SM, SN, SRCI, and WLL; Production adjusted for non-controlling interest where applicable; (2)DrillingInfo as of October 19, 2018; (3) Production per debt-adjusted share (DAS) from Evercore ISI as of October 22, 2018; Peers include APA, APC, AR, CHK, CLR, CNQ-TSE, COG, CPE, CXO, DVN, ECA, EGN, EOG, EQT, FANG,MRO, NBL, NFX, OAS, PXD, QEP, RRC, SU-TSE, SWN, WLL, WPX, and XEC; (4) FactSet as of October 30, 2018; Parsley shares priced at $18.50 per share on May 22, 2014; (5) Development inventory includes operated locations inLower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones; As of 11/1/2018 pro forma for pending divestiture; (6) Based on YTD 2018 activity levels in each development area as of October 30, 2018.

Create Shareholder Value

% of Dev Inventory Drilled(5)

% of Dev Inventory Remaining(5)

Inventory Life at Current Pace(6)

► Fastest to 100 MBoe/d(1)

► 7th Largest Permian Rig Program(2)

ANDREWS

MARTIN HOWARD

ECTOR

MIDLAND

GLASSCOCK

REAGAN

UPTON

CRANE

REEVESPECOS

CentralBasin

Platform

► One of 5 operators to generate positive shareholder return since Parsley IPO(4)

Delaware Basin

Midland Basin

(3) (4)

Milestones►Mid-teens after-tax CROCI(1)(2)

►Free cash flow by YE19(2)(3)

Stable development pace until self-funded

growth achieved

Enhancedoperational efficiency

► Top-tier corporate returns

► Increasing free cash flow

► Robust production growth per share

Frac Crews

Guiding Principles

5

Organic Path to Self-Funded Growth

(1) Cash return on capital invested (CROCI) is a non-GAAP financial measure and is defined as ((cash flow from operations + after-tax interest expense) / (average gross PP&E + average non-cash working capital)); (2) At NYMEX stripprices as of publication date; (3) Free cash flow/outspend is a non-GAAP financial measure and is defined as (cash flow from operations before changes in operating assets and liabilities - development capital expenditures).

Target Outcomes

Application – 2019 Outline

Excess cash flow creates growth rate optionality

2017 2018$0

Outspend(3)

Steady development pace accelerates progress toward free cash flow generation

Process►Steady development pace► Increasing operational efficiency► Intensive cost control

Operated Horizontal Rigs

► Discipline – require strong return on incremental

development dollar

► Foresight – anticipate constraints and capture

counter-cyclical opportunities

► Stability – manage financial and operational

risk to ensure execution of plan

Parsley’s Investment Framework

20%

25%

30%

35%

40%

45%

50%

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2014 2015 2016 2017 2018YTD

Percent of “One-R

un” LateralsAver

age

Late

ral L

engt

h (ft

.)

6

Operational Momentum Building

(1) Operational day measured as days equipment is active. Does not include mobilization or other idle time; (2) “One-run” lateral defined as a lateral drilled in one trip without any trips back up hole for various equipment maintenance orreplacement needs.

Increasing Operational Velocity

400

600

800

1,000

1,200

1,400

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

Feet

Stimulated Lateral Feet per Operational Day per Crew

Drilled Feet per Operational Day per Rig

Parsley record:► Over 420,000’ stimulated lateral feet and

46 wells placed on productionPermian Basin record:► Drilled longest “one-run”(2) slimhole lateral

(2.5 mile lateral in Glasscock County)

3Q18 Records

New Efficiency Thresholds

Efficient Drilling on Longer Laterals

(1)

(1)

Percentage of “one-run” laterals increased alongside increase in lateral lengths

7

Intensive Cost Control

► Capital costs driven lower by shorter cycle times, longer laterals, and increased regional sand usage

(1) Drilling & Completion Capital Expenditures per Lateral Foot calculated using company reported capital expenditures (accrual basis) and announced lateral lengths per the respective quarterly earnings releases; Not normalized forMidland and Delaware activity mix; (2) Per-unit operating costs include lease operating expenses, cash based general & administrative expenses (exclusive of stock-based compensation), and production and ad valorem taxes. Note:transportation and processing costs excluded for comparison purposes.

$8

$10

$12

$14

$16

$18

$20

$22

Operating C

osts ($/Boe) (2)

Operating costs per Boe

below $10

$600

$700

$800

$900

$1,000

$1,100

1Q18 2Q18 3Q18

Dril

ling

& C

ompl

etio

n C

apita

l Exp

endi

ture

s pe

r Lat

eral

Foo

t ($/

ft)(1

)

2014 2015 2016 2017 2018

D&C capex per lateral foot declined 9% Q/Q

► Peer-leading LOE and company-record G&A keep unit operating costs near company-lows

Reduced Drilling & Completion Costs Low Operating Costs

$40

$44

$48

$52

$56

$60

$64

$68

$72

$76

$80

25

30

35

40

45

50

55

60

65

70

75

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

WTI C

ushing ($/Bo) (2)

Net

Oil

Prod

uctio

n (M

Bo/d

)

8

Capitalizing on Counter-CyclicalInvestments

(1) U.S. Bureau of Labor Statistics, Producer Price Index by Industry: Oil and Gas Extraction [PCU21112111], retrieved from FRED, Federal Reserve Bank of St. Louis; (2) Bloomberg.

Accelerating Development During Lower Service Cost Environment Enabled…

Robust Oil Growth in HigherCommodity Price Environment

More than doubledoil volumes

“In light of anticipated tightness in the market for high-specification drilling rigs, Parsley proactively secured all of the rigs necessary to execute its 2017 drilling program.”

- Parsley 2Q17 Earnings Release

130

138

146

154

162

170

178

6

8

10

12

14

16

18

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

Oil & G

as Extraction Producer Price Index(R

olling 2-Month Average)Ope

rate

d H

oriz

onta

l Rig

s

(1)

More than doubled operated rig count

-$20

-$10

$0

$10

$20

$30

$40

-$40

-$20

$0

$20

$40

$60

$80

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

Market Im

plied Midland/G

ulf C

oast Differential ($/B

o)

Par

sley

Unh

edge

d O

il P

rice

Rea

lizat

ion

($/B

o)

PE Unhedged Oil Price Realization (Net of Gathering Fee)Midland/Gulf Coast Forward Differential

$50

$55

$60

$65

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

Unh

edge

d O

il P

rice

Rea

lizat

ion

($/B

o)

9

Oil Flowing at Advantaged Price

► Finalized previously announced marketing agreements to bolster takeaway runway and support growth plans

► Proactive marketing strategy continues to deliver flow assurance and strong pricing

►Ongoing exposure to Gulf Coast pricing mitigates impact of Midland differentials and translates to healthy projected realizations during Permian infrastructure buildout

►Negotiated favorable pricing on longer-term agreements

► Expect ~$2/Bbl differential to Gulf Coast price on barrels covered by firm transport in 2020(3)

► Additional diversification through exposure to international pricing

Marketing strategy centered around two guiding principles: dependability and diversification

(4)

(5)

Expect consistently strong realizations even during

period of relative Midland price weakness

(1) PE realized price shown net of gathering fee. Peers include CDEV, CPE, CXO, EGN, FANG, HK, LPI, MTDR, and SM. Permian only oil realizations shown where applicable; (2) Midland price represents Bloomberg-sourced 3Q18average WTI Midland price; (3) Differential to Gulf Coast refers to expected realized price relative to Magellan East Houston (MEH) benchmark and excludes gathering fees; (4) Weighted average realization based on anticipatedexposure to MEH, Cushing, and Midland benchmarks using Bloomberg-sourced futures pricing for each as of 10/26/2018; net of gathering fee at assumed $1.25/Bo; Range primarily based on pipeline start-up timing and variablepricing agreements; (5) Midland/Gulf Coast forward differential based on Bloomberg-sourced futures pricing for Midland and MEH benchmarks as of 10/26/2018.

3Q18 2Q18

Historical & Illustrative Oil Price Realizations

Leading Oil Price Realization(1)

(2)

10

Operational Spotlight - Martin County

(1) Normalized to 10,000’ lateral; Martin County Industry Average calculated using DrillingInfo and represents average of all Martin County horizontal wells placed on production between January 1, 2017 and August 31, 2018.

Robust Well Performance(1)

Parsley AcreageHayden PadStrain Ranch PadWater Recycling Center

Recent Martin County well results showcase top-tier rock quality:

►Strong results from recent three-well projects targeting the Wolfcamp A and B formations:

►Average IP30 of 1,560 Boe/d (80% oil) (Hayden)

►Parsley-record 30-day oil rate for a three-well pad

►Average IP30 of 1,435 Boe/d (74% oil) (Strain Ranch)

►Both pads outpacing industry average Martin County productivity

0

10

20

30

40

50

60

70

80

90

100

0 30 60 90 120

Cum

ulat

ive

Oil

Pro

duct

ion

(MB

o)

Martin County Industry Average (2017-2018)Strain Ranch 3-Well AverageHayden 3-Well Average

Successful water recycling pilot supports increased development:

►Over 100K barrels of recycled water utilized during Hayden pad completion

►Strong results suggest no apparent productivity degradation

MARTIN HOWARD

MIDLAND

GLASSCOCK

MidlandBasin

Ramping Martin Co. Development

11

Pruning the Portfolio

(1) Includes recent divestitures with signed purchase and sales agreements and select acreage trade where Parsley received cash proceeds as part of the transaction; (2) Development inventory includes operated locations in LowerSpraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones.

Committed to the Core Bringing Tail-End Value Forward

Targeted Divestitures(1)

MARTIN HOWARD

MIDLAND

UPTON

REAGAN

GLASSCOCK

MidlandBasin

Parsley AcreageDivested Acreage

IRION

Summary: Monetized portion of central Reagan, southern Upton, and northern Howard acreage, comprised of tail-end inventory

Transaction DetailsNet Acreage: ~11,850 Net Acres

Net Development Locations(2): 256 Locations(~5,100’ Avg. Lateral)

3Q18 Net Production: ~1,200 Boe/d (~55% Oil)

Cash Proceeds: ~$170 millionExpected Close Dates: By Year-end 2018

Disciplined pruning program brings value forward and recycles capital

into high-return areas

0%

2%

4%

6%

8%

10%

12%

14%

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

PE Peer 1 Peer 2 Peer 3 Peer 4

Percent Draw

n on Revolver

Liqu

idity

($M

M)

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

Favorable Debt Maturity Schedule

Advantaged Liquidity Profile(1)

12

Strong, Flexible Financial Position

$1,000

$1,300

$400 $650

$700 $450

2018 2019 2020 2021 2022 2023 2024 2025 2026 2027Revolving Credit Facility ($MM) Senior Notes ($MM)

Committed Amount

Remaining Borrowing

Base

1H25

2H25

$1,100

$2,300

(2)

►Peer-leading(1) liquidity of $1.3 billion(2)

►Healthy leverage ratio of 1.5x(3) LTM EBITDAX

►Favorable debt maturity schedule with earliest notes maturity in 2024

►Weighted average cost of debt has dropped~200 bps since mid-2016

(1) Permian SMID-Cap peers include CDEV, CPE, JAG, and LPI. Calculated as availability on committed portion of borrowing base plus cash and cash equivalents. Peer data obtained from 2Q18 filings and pro forma for subsequentdebt offerings, acquisitions, and divestitures; (2) As of September 30, 2018 and pro forma for expected proceeds of ~$165 million from subsequent acreage divestiture and trade announced 11/1/2018; (3) Leverage ratio calculated asnet debt at September 30, 2018 pro forma for expected proceeds of ~$165 million from subsequent divestiture and trade announced 11/1/2018 divided by last twelve-month Adjusted EBITDAX; Adjusted EBITDAX is not presented inaccordance with generally accepted accounting principles in the United States (“GAAP”). For reconciliation of the non-GAAP financial measure of adjusted EBITDAX to the most directly comparable GAAP financial measure, please seethe Supplementary Slides.

2018E (Unchanged)

Production

Annual Net Oil Production (MBo/d) 68.0 - 70.5

Annual Net Production (MBoe/d)(1) 106.0 - 111.0

Capital Program

Total Development Expenditures ($MM) $1,650 - $1,750

Drilling & Completion (% of Total) 85 – 90%

Facilities, Infrastructure & Other (% of Total)

10 – 15%

Activity

Gross Operated Horizontal POPs(2) ~165

Midland Basin (% of Total) ~75%

Delaware Basin (% of Total) ~25%

Average Lateral Length ~9,500’

Average Working Interest 95 – 97%

Net Operated Horizontal POPs(2) 157 - 160

Units Costs

Lease Operating Expenses ($/Boe)(1) $3.50 - $4.25

Cash G&A ($/Boe)(1) $3.25 - $3.65

Production & Ad Valorem Taxes (% of Revenue)

6.0 – 7.0%

13

Guidance Summary

4Q18 rig and frac spread utilization rate will be dictated by 2018 capital budget

(1) Incorporates adoption of ASC 606; (2) Wells placed on production.

► Commitment to 2018 capital budget is priority

► Reduced 3Q18 service and equipment utilization to accommodate efficiency gains

► Recently announced divestitures do not impact 2018 guidance

Disciplined Approach

60%

70%

80%

90%

0

5

1Q18 2Q18 3Q18 4Q18E

Frac Spread UtilizationDedicated Frac Spreads

Supplementary Slides

15

High Rankings on Key Value Drivers

(1) SGS E&P Comp Sheets (October 19, 2018). 2Q18 Operating Margin; (2) FactSet; Based on 2Q18 reported production; (3) SGS E&P Comp Sheets (October 19, 2018). Recycle ratio is equal to operating margin divided by PD F&D.F&D costs based on 2017 data and operating margin based on 2Q18. PE recycle ratio includes actual 2017 PD F&D/Boe of $12.10; (4) DrillingInfo as of October 20, 2018; (5) Debt-adjusted per share (DAPS) production growth CAGR2014 to 2018e. Evercore ISI October 22, 2018. Peers include APA, APC, AR, CHK, CLR, COG, CPE, CXO, DVN, ECA, EOG, FANG, MRO, NBL, NFX, OAS, PXD, QEP, RRC, SWN, WLL, WPX, and XEC; (6) Peers include APA, APC,AR, AXAS, CDEV, CHK, CLR, COG, CPE, CRC, CRK, CRZO, CXO, DVN, ECA, ECR, EOG, EPE, ESTE, FANG, GDP, GPOR, HES, JAG, LGCY, LONE, LPI, MCF, MRO, MTDR, MUR, NBL, NFX, OAS, OXY, PDCE, PQUE, PXD,QEP, REI, REN, RRC, SD, SM, SN, SRCI, SWN, WLL, WPX, WRD, WTI, XEC, and XOG; (7) Valuations from FactSet as of October 20, 2018 defined as Enterprise Value divided by consensus 2018 EBITDAX estimate.

Operators with Top Quartile Valuation(7)

Operating Margin(1)(6)

Recycle Ratio(3)(6)% Oil(2)(6)

2014-2018EDAPS Growth(5)

Horizontal Rigs In Lower-48(4)(6)

Rel

ativ

e R

ank

Asset Quality & Operational Efficiency

Commodity Weighting Scale & Growth

Parsley Energy

Average Rank of Operators with Top Quartile Valuation(7)

Average Rank of Operators with Bottom Quartile Valuation(7)

Operators with Interquartile Valuation(7)

Operators with Bottom Quartile Valuation(7)

$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

-40% -20% 0% 20% 40% 60% 80% 100%

2Q18

Ope

ratin

g M

argi

n ($

/Boe

)(4)

Historical 2-Year Production CAGR(5)

0%

12%

24%

36%

48%

60%

72%

84%

0

20

40

60

80

100

120

140

Operating C

ash Margin Percentage

(1)

Net

Pro

duct

ion

(MBo

e/d)

16

High Margin Growth Trend

(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, pleasesee “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 margindefined as realized price per Boe excluding hedges less per-unit operating costs. Per-unit operating costs include lease operating expenses, cash based general & administrative expenses (exclusive of stock-based compensation),production and ad valorem taxes, and, if recorded during the period, transportation and processing costs. For all periods in 2018, operating cash margin percentage reflects adoption of ASC 606; (2) May 23, 2014; (3) Peers includeAPA, APC, AR, AREX, AXAS, CHK, CLR, COG, CPE, CRC, CRK, CRZO, CXO, DNR, DVN, ECA, ECR, EGN, EOG, EPE, ESTE, FANG, GDP, GPOR, GST, HES, HK, HPR, JONE, LGCY, LONE, LPI, MCF, MRO, MTDR, MUR, NBL,NFX, NOG, OAS, OXY, PDCE, PQUE, PXD, QEP, REI, REN, RRC, SD, SM, SN, SRCI, SWN, TALO, WLL, WPX, WTI, and XEC; (4) 2Q18 unhedged operating margins as reported in SGS E&P Comp Sheets; operating margin isdefined as realized price per Boe excluding hedges less per-unit lease operating expenses, transportation & gathering costs, total general & administrative expenses, production and ad valorem taxes, and other operating expenses;(5) FactSet; 2-Year CAGR calculated using 2Q18 and 2Q16 reported total production.

► Steep production ramp accompanied by robust margin expansion► Retained almost 80% of healthy realized price as marketing advantages, operating cost compression,

and scale benefits flow through

2015 2016 2017 2018

14% quarterly production CAGR

since IPO(2)

Strong Growth and Expanding Margins… Set Pace Among Peers(3)

0%

2%

4%

6%

8%

10%

12%

14%

-40% -30% -20% -10% 0% 10% 20% 30% 40%

Cas

h R

etur

n on

Cap

ital I

nves

ted,

Ave

rage

201

5-17

(2)

Production per debt-adjusted share, 2015-17 CAGR

17

The Right Balance

(1) Goldman Sachs Global Investment Research; October 2018; Peers include APA, APC, AR, CHK, CLR, CNX, COG, COP, CRC, CRZO, CXO, DNR, DVN, ECA, EOG, EQT, FANG, GPOR, HES, LPI, MRO, MUR, NBL, NFX, OAS,OXY, PDCE, PXD, QEP, RRC, SWN, WLL, WPX, and XEC; (2) Cash Return on Capital Invested (CROCI) is a non-GAAP financial measure and Goldman Sachs Global Investment Research defines it as ((cash flow from operations +after-tax interest expense) / (gross PP&E + goodwill + working capital and other assets)).

Elite Combination of Growth and Returns(1)

Top-tier returns throughout during

intensive growth and asset expansion phase

Median: -3%

Median: 6%

$10

$15

$20

$25

$30

$35

$40

3Q16

4Q16

1Q17

2Q17

3Q17

4Q17

1Q18

2Q18

3Q18

NG

L R

ealiz

atio

ns E

xclu

ding

Effe

ct o

f Hed

ges

($/B

bl)

OPIS Mt. Belvieu NGL Basket PE Peers

18

Capturing the NGL Upswing

►High quality NGL barrel

►Aligned contract structure

►Favorable recovery rates

►Ample partner-controlled fractionation capacity

(1) OPIS Mont Belvieu NGL Basket calculated with historical NGL prices from Bloomberg and weighting consistent with ICE Futures contract definition of NGL Basket, OPIS Mt. Belvieu Non-TET Future contract; 42% ethane, 28%propane, 11% butane, 6% iso-butane, and 13% natural gasoline; (2) Quarterly filings; peers include CDEV, EGN, FANG, JAG, LPI, and PXD.

Harvesting Higher NGL Prices

Realized 88% of Mont Belvieu price in 3Q18

(1)

Favorable NGL Dynamics

(2)

19

Oil Hedge Position

Crude Realizations Not Constrained by Swaps(7)

► Aligning hedges with regional price exposure

► Hedge structure retains upside to higher oil prices

Hedge positions as of 11/1/2018. Prices represent the weighted average price of contracts scheduled for settlement during the period; (1) When the reference price (WTI, Midland, or MEH) is above the long put price, Parsley receivesthe 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 thedifference 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) isabove 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 thereference price; (4) Premium realizations represent net premiums paid (including deferred premiums), which are recognized as a loss in the period of settlement; (5) Parsley receives the swap price; (6) These positions hedge the timingrisk 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 theweighted average prices of the delivery month, the next month, and the following month during the period when the delivery month is the first month; (7) BMO Capital Markets; Peers include CPE, CXO, FANG, JAG, LPI, and REN. WTIstrip from FactSet as October 26, 2018.

$30

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

Dollar per B

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aps

4Q18E Swap Coverage (Left Axis) 2019E Swap Coverage (Left Axis)

4Q18E Swap Price (Right Axis) 2019E Swap Price (Right Axis)

4Q18 WTI Strip (Right Axis) 2019 WTI Strip (Right Axis)

Open Crude Oil Derivatives Positions4Q18 1Q19 2Q19 3Q19 4Q19 1Q20 2Q20

OPTION CONTRACTS

CUSHING

Put Spreads – Cushing (MBbls/d)(1) 37.5 20.0 19.8 24.5 24.5 Long Put Price ($/Bbl) $49.67 $54.17 $54.17 $58.83 $58.83

Short Put Price ($/Bbl) $39.67 $44.17 $44.17 $48.83 $48.83

Three Way Collars - Cushing (MBbls/d)(2) 31.0 8.3 8.2 9.8 9.8 Short Call Price ($/Bbl) $75.65 $80.40 $80.40 $80.33 $80.33

Long Put Price ($/Bbl) $50.00 $50.00 $50.00 $50.83 $50.83

Short Put Price ($/Bbl) $40.00 $40.00 $40.00 $40.83 $40.83

Collars – Cushing (MBbls/d)(3) 3.0 Short Call Price ($/Bbl) $61.31

Long Put Price ($/Bbl) $45.67

MIDLAND

Put Spreads – Midland (MBbls/d)(1) 11.7 14.8 4.9 4.9 Long Put Price ($/Bbl) $50.71 $50.56 $60.00 $60.00

Short Put Price ($/Bbl) $40.71 $40.56 $50.00 $50.00

MEH

Put Spreads – MEH (MBbls/d)(1) 3.3 3.3 8.2 8.2 5.0 4.9 Long Put Price ($/Bbl) $70.00 $70.00 $64.00 $64.00 $70.00 $70.00

Short Put Price ($/Bbl) $60.00 $60.00 $54.00 $54.00 $60.00 $60.00

Total Option Contracts (MBbls/d) 71.5 43.3 46.1 47.4 47.4 5.0 4.9

Premium Realization ($MM)(4) ($19.1) ($12.4) ($13.3) ($13.6) ($13.6) ($1.6) ($1.6)

BASIS SWAPS

Midland-Cushing Basis Swaps (MBbls/d)(5) 18.5 21.7 8.9 Swap Price ($/Bbl) ($3.76) ($8.42) ($8.94)

MEH-Cushing Basis Swaps (MBbls/d)(5) 2.2 2.1 2.1 2.1 Swap Price ($/Bbl) $5.10 $5.10 $5.10 $5.10

ROLLFACTOR SWAPS

Rollfactor Swaps (MBbls/d)(6) 15.0 Swap Price ($/Bbl) $0.60

20

Adjusted EBIDAX Reconciliation

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

Unaudited, in thousands

2018 2017 2018 2017Adjusted EBITDAX reconciliation to net income:

Net income (loss) attributable to Parsley Energy, Inc. stockholders $113,309 ($13,333) $315,354 $56,855

Net income (loss) attributable to noncontrolling interests 20,840 (1,828) 65,216 22,068

Depreciation, depletion and amortization 157,352 94,819 424,103 247,104

Exploration amd abandonment costs 11,140 88 19,917 4,223

Interest expense, net 32,854 22,879 98,580 64,979

Interest income (1,055) (1,013) (4,864) (5,562)

Income tax expense (benefit) 32,454 (5,080) 89,022 25,538

EBITDAX $366,894 $96,532 $1,007,328 $415,205

Change in TRA liability - - 82 20,549

Stock-based compensation 4,686 5,170 15,118 14,630

Acquisition costs - 2,449 2 10,969

Gain on sale of property (1,383) - (6,438) -

Accretion of asset retirement obligations 361 268 1,074 597

Loss on early extinguishment of debt - - - 3,891

Inventory write down 451 - 495 -

Loss (gain) on derivatives 22,514 61,955 42,773 (6,175)

Net settlements on derivative instruments 9,376 10,982 (516) 15,654

Net premiums on options that settled during the period (17,853) (12,487) (52,451) (22,404)

Adjusted EBITDAX $385,046 $164,869 $1,007,467 $452,916

Three Months Ended September 30, Nine Months Ended September 30,

21

Operating Cash Margin Reconciliation

$ in thousands

2018 2017 2018 2017

Net income (loss) attributable to Parsley Energy, Inc. stockholders $113,309 ($13,333) $315,354 $56,855

Net income (loss) attributable to noncontrolling interests 20,840 (1,828) 65,216 22,068

Income tax expense (benefit) 32,454 (5,080) 89,022 25,538

Other revenues (2,369) (8) (7,916) (3,533)

Depreciation, depletion and amortization 157,352 94,819 424,103 247,104

Exploration and abandonment costs 11,140 88 19,917 4,223

Stock-based compensation 4,686 5,170 15,118 14,630

Acquisition costs - 2,449 2 10,969

Accretion of asset retirement obligations 361 268 1,074 597

Other operating expenses 6,129 2,419 10,781 8,275

Interest expense, net 32,854 22,879 98,580 64,979

Gain on sale of property (1,383) - (6,438) -

Prepayment premium on extinguishment of debt - - - 3,891

Derivative loss (gain) 22,514 61,955 42,773 (6,175)

Change in TRA liability - - 82 20,549

Interest income (1,055) (1,013) (4,864) (5,562)

Other expense (income) 76 (508) (459) (1,281)

Operating cash margin $396,908 $168,277 $1,062,345 $463,127

Operating cash margin per Boe $37.13 $25.57 $36.75 $26.61

Average price per Boe, without realized derivatives $47.58 $36.62 $47.17 $37.47

Operating cash margin percentage 78% 70% 78% 71%

Three Months Ended September 30, Nine Months Ended September 30,

22

Impact of ASC 606 Adoption

ASC 605 Adjustment ASC 606

Production revenues (in thousands):Oil sales $424,549 -- $424,549 Natural gas sales 11,509 1,301 12,810Natural gas liquids sales 64,100 7,194 71,294 Total production revenues 500,158 8,495 508,653Operating expensesTransportation and processing costs -- 8,495 8,495Production revenues less transportation and processing costs $500,158 -- $500,158

Net income attributable to Parsley, Inc. stockholders (in thousands) $113,309 -- $113,309

Production:Oil (MBbls) 6,763 -- 6,763

Natural gas (MMcf) 8,791 1,087 9,878

Natural gas liquids (MBbls) 2,012 269 2,281

Total (MBoe) 10,240 450 10,690

Average daily production volume:Oil (Bbls) 73,511 -- 73,511Natural gas (Mcf) 95,554 11,816 107,370Natural gas liquids (Bbls) 21,870 2,923 24,793Total (Boe) 111,304 4,892 116,196

Certain unit costs (per Boe):Lease operating expenses $3.88 ($0.16) $3.72 Transportation and processing costs -- $0.79 $0.79 Production and ad valorem taxes $2.99 ($0.13) $2.86 Depreciation, depletion and amortization $15.37 ($0.65) $14.72 General and administrative expenses (including stock-based compensation) $3.67 ($0.16) $3.51 General and administrative expenses (cash based) $3.21 ($0.14) $3.07

Three Months Ended September 30, 2018

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 (using unweightedaverage 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, unlessevidence 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 estimated provedreserves 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 theSEC’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 inthis presentation, such estimates have been prepared internally by our engineers and management without review by independent engineers. These estimates are by their naturemore speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas orzones 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 theCompany. 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 ofthe 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 propertiesprovides additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Our related expectations for future periods aredependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future drilling activity and activity that may beaffected 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 drillingand completion cost estimates that do not include facilities, land, seismic, general and administrative (“G&A”) or other corporate level costs.

Proved Developed Finding and Development (“F&D”) 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.