investor presentation september...

INVESTOR PRESENTATIONSeptember 2017

Forward Looking Statements and Cautionary Statements

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 Litigation Reform Act of 1995. Allstatements, 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 statementsare 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 are difficult to predict and many ofwhich 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 pricevolatility, inflation, lack of availability 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 of development expenditures andthe 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 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 required by applicable law, we disclaimany 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 andoutcome 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 industry publications, governmentpublications 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 accuracyor 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 describedabove.

Oil & 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 be estimated with reasonablecertainty 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 monthprices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain,regardless of whether deterministic or probabilistic methods are used for the estimation.

In this presentation, proved reserves attributable to Parsley as of 12/31/16 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on SEC pricing, as adjusted formarket differentials, transportation fees, and quality, of $39.36 / Bbl crude, $2.23 / Mcf gas, and $15.03/ Bbl NGL. References to our estimated proved reserves as of 12/31/16 are derived from ourproved 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 ofproved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Parsley from including in filings with the SEC. Unless otherwise stated in this presentation, such estimates havebeen 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 andpossible 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 theseestimates 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 ourproperties 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 actualencountered 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 changesignificantly as development of our properties provides additional data and therefore actual quantities that may ultimately be recovered will likely differ from these estimates. Our relatedexpectations 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 andactivity 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 costestimates that do not include facilities, land, seismic, general and administrative (“G&A”) or other corporate level costs.

Superior acreage portfolio

Premier combination of acreage quality and quantity

Large, concentrated development blocks in heart of Midland Basin and S. Delaware Basin oil windows

Ongoing consolidation, lateral extension, and inventory uplift through acreage trades

Established track record of operational and capital efficiency

Robust operating margins and top-tier recycle ratio

Differentiated organic oil growth per dollar invested

Efficient and sustainable growth profile

Low reinvestment risk with decade plus inventory of premium drilling locations in proven target intervals

Flexible, low-risk development plan with strong hedge book and secured services and equipment

Financial flexibility with strong balance sheet

No debt outstanding and $500 MM in cash at end of 2Q17

Organic resource expansion

Favorable well productivity trends via ongoing completion design evolution

Unlocking inventory upside through delineation of new target zones and spacing configurations

Parsley Energy Overview

3

Market Snapshot

Parsley Leasehold

NYSE Symbol: PEMarket Cap: $7,876 MM(1)

Net Debt: $997 MM(2)

Enterprise Value: $8,873 MMShare Count: 314 MMPermian Basin Net Leasehold Acreage: ~231,000

Midland Basin: ~179,000Delaware Basin: ~52,000

Permian Basin Net Royalty Acreage: ~7,000

Note: All data as of end 2Q17 pro forma for subsequent acreage trades; (1) Calculated using 8/31/2017 closing price; (2) Net Debt is a non-GAAP financial measure that is defined as total debtless cash and cash equivalents.

Parsley Energy Leasehold

Premier Permian Pure-Play

ANDREWSMARTIN

ECTOR

LEA

WINKLERLOVING

WARDCRANE

REEVESPECOS

UPTON

MIDLAND

GLASSCOCK

REAGAN

HOWARD

Sustained Production Momentum

4

Strong production momentum despite intensive delineation agenda

2Q17 daily net production up 18% versus 1Q17 and 81% year-over-year

At 2Q17 update, raised full-year and 4Q17E production guidance

16% compound quarterly production growth rate over thirteen quarters as a public company(1)

(1) Parsley completed its initial public offering on May 29, 2014

Quarterly Production Trajectory

Production Guidance (Net MBoe/d)

65 - 7167 - 73

78 - 8880 - 90

2017E(Previous)

2017E(Updated)

4Q17E(Previous)

4Q17E(Updated)

9.2

64.7

80.0 - 90.0

0

20

40

60

80

100

MBo

e/d

Net Production (MBoe/d)

0.00

1.00

2.00

3.00

4.00

5.00

6.00

Top-Tier Capital Efficiency

5

Source: SGS E&P Comp Sheets – Week Ending June 23, 2017. Companies include APA, APC, AR, BBG, CHK, CLR, CNX, COG, CPE, CRC, CRK, CRZO, CXO, DNR, ECA, ECR, EGN, EOG, EPE,EQT, FANG, GPOR, HES, HK, JONE, LPI, MRO, MTDR, MUR, NBL, NFX, NOG, OAS, OXY, PDCE, PE, PXD, QEP, REN, RICE, RRC, RSPP, SD, SGY, SM, SN, SRCI, SWN, UNT, WLL, WPX, WTI, XCO,and XEC. Operating margin based on 1Q17. Oily E&P Companies are defined as companies with oil accounting for 40% or more of 2016 production, and Gassy E&P Companies are defined ascompanies with oil accounting for less than 40% of 2016 production. (1) Based on 2016 data. Recycle ratio is equal to operating margin divided by PD F&D. PE recycle ratio includes actual 2016PD F&D/Boe of $8.04.

Rank in top 10% of E&P universe on key capital efficiency measures

Superior capital efficiency translates to value-adding-growth

Position at low end of cost curve incents differentiated growth profile

Recycle Ratio(1)

Oily E&P Companies Gassy E&P Companies

Parsley Energy

Operating Margin ($/Boe)

$0

$5

$10

$15

$20

$25

$30

$35

Parsley Energy


$503

$997

$1,500 MM

Cash on hand First lien credit facility

Peer-leading(1) liquidity of $1.5 billion provides ample flexibility to fund efficient growth plan

Fully undrawn borrowing base of $1.4 billion, with company-elected commitment of $1.0 billion

Favorable maturity schedule, with earliest notes maturity in 2024

Strong Financial Position

6

Favorable Debt Maturity Schedule

$1,000

$650

$450

$1,400

$400

$1,100

2017 2018 2019 2020 2021 2022 2023 2024 2025

($M

M)

Borrowing Base Senior Notes

Committed Amount

Borrowing Base

1H25

2H25

Ample Liquidity

(2)

Liquidity vs. SMID-Cap Peers ($MM)(1)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

PE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

Cash on Hand Borrowing Base Availability

(1) Permian SMID-Cap peers include CPE, EGN, FANG, LPI, and RSPP. Calculated as availability on committed portion of borrowing base plus cash on hand. Peer data obtained from 2Q17presentations and filings. (2) Committed portion; net of letters of credit on the Company’s fully undrawn revolver.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Proactive hedging program protects cash flow and balance sheet

Over 90% of consensus oil volumes hedged in 2018

Significantly more hedge protection than peers in 2018

Heightened visibility facilitates operational continuity and steady execution

Substantial Oil Hedge Position

7

$0

$10

$20

$30

$40

$50

$60

0

15

30

45

60

75

90

3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

WTI ($/Bbl)M

Bbls

/d

MBbls/d Hedged Consensus MBbls/d Weighted Average Long Put Price

Hedge positions as of 8/24/2017; (1) Source: Wells Fargo E&P: Mile High View dated August 11, 2017. Operators include APA, BBG, CLR, CRZO, CXO, DVN, EOG, EPE, FANG, JAG, LPI, MTDR,NFX, OAS, PE, PXD, REN, RSPP, SRCI, WLL, WRD, and XOG. Includes operators with 2016 oil production greater than or equal to 40% of total production; Parsley data reflects the Company’shedged oil volumes as of 8/24/2017 as a percentage of consensus oil volumes; (2) FactSet consensus estimates as of 8/24/2017; (3) Excludes swaps

Oil Volumes Hedged

Estimated Percent of 2018 Oil Hedged(1)

(3)

Parsley Energy

4 operators with 0% hedged

(2)

Accretive Acreage Trades

8

Recent acreage trades enhance development potential of core operated footprint

Traded out of scattered non-operated properties with low working interest (“WI”) into concentrated operated properties with high WI

~25% average WI on acreage traded away ~85% average WI on acreage traded for

Recent trades added more than 500,000 net lateral feet to horizontal drilling inventory, on top of 900,000 net lateral feet previously added following Double Eagle (“DEEP”) acquisitions

Post-DEEP trades akin to adding ~5,600 premium net acres with four target intervals(1)

Midland Basin Acreage Trades

Trade Spotlight – “Four Corners” Trade

Leasehold Acquired via Trade

Leasehold Traded Away


Gained operatorship of core “Four Corners” acreage block

Traded away 24 net non-operated locations with 21% average WI

Added 56 net operated locations with 85% average WI

Effectively adds 31 net operated locations near the front of Parsley’s drilling inventory at no cost

Potential for subsequent fill-in trades to further increase associated inventory

HOWARD

GLASSCOCK

REAGAN

UPTON

MIDLAND

MARTIN

(1) Assumes 32 wells per drilling spacing unit (DSU) and that 7,500’ stimulated lateral length wells correspond to a 960 acre DSU

Delineation Milestones

9


GLASSCOCK

REAGAN

UPTON

MIDLAND

WARD

PECOS

REEVES

Midland Basin Delineation

Delaware Basin Delineation

Midland Basin Delineation Objectives

First Wolfcamp C well

First Upper Wolfcamp A well

330’ Downspacing in Upper/Lower Wolfcamp B

Compressed stage spacing test

Second Wolfcamp C well

1

2

3

4

5

2

3

45

Southern Delaware Basin Delineation Objectives

First Upper Wolfcamp A well

First Wolfcamp B well

1

2

21

1


0

150

300

450

600

0

1,000

2,000

3,000

4,000

0 30 60 90 120 150 180

Cumulative Production

(MBoe)

Dai

ly P

rodu

ctio

n(B

oe/d

)

Days of Production

GlasscockNose

CBP

Wolfcamp C Play Fairway

Paige Wolfcamp C

MARTIN

MIDLAND

UPTON

HOWARD

GLASSCOCK

REAGAN1,200’

10 mi.

Strong Indications from Wolfcamp C Interval

10

First Wolfcamp C well (Taylor) still naturally flowing and continues robust production trend with 255,000 barrels of oil recovered through 180 days(1)

Achieved payout within six months(2)

Second Wolfcamp C well (Paige) reported IP20 rate of over 2,000 Boe/d (~65% oil)

Aggressively incorporating Wolfcamp C in development program, with several wells in process or to be drilled by year-end

Abundant inventory in Wolfcamp C play fairway, characterized by favorable thermal maturity and substantial thickness and reservoir pressure

Taylor Wolfcamp C Exceeding 1 MMBoe Type Curve by ~135%(3)

(1) Normalized for downtime; (2) Based on realized commodity prices; (3) 3-stream; Normalized for downtime; 1 MMBoe type curve normalized to Taylor lateral length (approx. 10,000’)

Wolfcamp C Fairway & Well Locations

200’400’

600’800’

1,000’1,200’GROSS THICKNESS

Taylor Wolfcamp C

2017 Planned Wolfcamp C

900+ Wolfcamp C Locations in the Play Fairway

Increasing GOR and decreasing reservoir pressure to south and east(red arrows)

Second Wolfcamp A Landing Zone Confirmed

11

Encouraging results from first Upper / Lower Wolfcamp A stack test, confirming a second landing zone in the Wolfcamp A interval

Pad average production keeping pace with 1 MMBoe EUR type curve

Significant inventory upside pending additional tests

Strong Production Trends from Upper / Lower WC A Stack Test

0

20

40

60

80

0 30 60 90

Cum

ulat

ive

Prod

ucti

on (

MBo

e)(1

)

Days of Production

Wolfcamp AStacked

Well Average1-Mile

Current InventoryInventory Upside

Upper / Lower WC A Stack Test (Online)

2nd WC A Stack Test Combined with WC B Stack

(1Q18)

Wolfcamp A

Wolfcamp B

330’ Spacing

(1) 3-stream; Normalized to 7,000’ stimulated lateral and for downtime

Upcoming project tests two Wolfcamp A targets stacked over two Wolfcamp B targets, showcasing

Parsley’s differentiated Wolfcamp thickness

800’

Stacked Upper / Lower Wolfcamp A Gun Barrel

0%

25%

50%

75%

100%

125%

150%

0% 5% 10% 15% 20% 25% 30%

% N

PV In

crea

se v

s. 6

60’

Spac

ed D

evel

opm

ent

Per Well Cost Savings from660’ Spaced Development

Promising Results from Wolfcamp B Downspacing Pilot

12(1) Standard 660’ Development: 4 wells with area-average type curve; Downspaced development: 8 wells at 330’ spacing; $50 oil, $3/mcf gas, $20 NGL

Initial results from 8-well Wolfcamp B project at 330’ spacing support downspacing potential with projected NPV uplift of 30%+ versus 660’ spaced development

Value uplift driven by favorable production rates and cost savings

For the 7 wells that have achieved 30-day peak rates, average IP30 of 960 Boe/d is 84% of offset wells with 660’ spacing

Dual-pad project design incorporates baseline cost savings of 5%, driven primarily by facilities and infrastructure efficiencies

Analysis suggests less intensive frac design could deliver comparable productivity at enhanced cost savings, driving additional NPV uplift

Downspaced Test Results Suggest Value-Add Potential(1)

330’ Production % of 660’

Downspaced Pad Design5% cost reduction &

84% production of 660’ spacing1-Mile

Current InventoryInventory Upside

330’ DownspacedProject

Wolfcamp B

Downspaced Wolfcamp B Pilot Gun Barrel

~230’

330’ Spacing

0

20

40

60

80

100

0 30 60 90

Cum

ulat

ive

Prod

ucti

on (

MBo

e)(1

)

Days of Production

Upper / Lower WC A Stagger Pad Well Average

Upper WC A / WC B Stack Pad Well Average

Three Productive Wolfcamp Targets in Pecos County

13

Positive results in two previously-untested Wolfcamp flow units in Pecos County, one above and one below traditional Lower Wolfcamp A landing zone

Lower Wolfcamp A / Wolfcamp B pad with stack configuration on pace with Pecos standalone well average

Upper / Lower Wolfcamp A pad with stagger configuration just 20% below Pecos standalone average

Promising Results in Wolfcamp Zone Delineation Tests

PECOS



2017 Wells Planned or In ProgressCompleted Horizontal Wells / Pads

Completed Vertical Wells1-Mile

Note: Current inventory count based on an average of two flow units across acreage

330’ Spacing

UpperWolfcamp A

Wolfcamp B

LowerWolfcamp A

200’

200’

Upper/Lower WC A Stagger

Lower WC A / WC B Stack

S. Delaware Wolfcamp A and B Gun Barrel

0

25

50

75

100

125

150

175

0 30 60 90 120 150 180

Cum

ulat

ive

Prod

ucti

on (

Mbo

e)(1

)

Days of Production

Louis 4413H (Compressed Stages) Louis 4415H (Standard Design)

Significant Productivity Gain with Compressed Stage Design

14

Initial Wolfcamp B compressed stage test outperforming direct offset with standard design by 20% with less than 5% incremental cost

Reduced stage spacing from ~170’ to ~100’, increasing number of total frac stages from ~30 to ~50

Parsley’s most prolific 1-mile Wolfcamp B well to date

Compelling early-time project economics

Design generated higher bottomhole pressures than standard design, indicating increased fracture efficiency and hydrocarbon recovery factor

Broad application could translate to portfolio-wide productivity increase

Several additional compressed stage tests planned in 2H17


Compressed Stage Test Outperforming Standard Design

+20% vs Standard Design

StandardDesign

CompressedStages

~170’ Stage Length

~100’~100’

5 clusters/stg

3 clusters/stg 3 clusters/stg

Compressed Stage Design Modification

2017 Guidance Summary

15

Unit Costs

LOE ($/Boe) $3.50 - $4.50 $3.50 - $4.50

Cash G&A ($/Boe) $4.00 - $5.00 $4.00 - $5.00

Production & Ad Valorem Taxes (% of Revenue)

6.0 - 7.0% 6.0 - 7.0%

Capital Program

Drilling & Completion ($MM) $840 - $960 $840 - $960

Infrastructure & Other ($MM) $160 - $190 $160 - $190

Total Development Expenditures ($MM) $1,000 - $1,150 $1,000 - $1,150

% Non-Operated 3 – 5% 3 – 5%

Activity

Gross Operated Horizontal Completions

Midland BasinDelaware Basin

Average Lateral Length

130 – 150

95 – 10535 – 45

~8,000’

120 – 140

95 – 10525 – 35

~8,000’

Gross Operated Vertical Completions 5 - 10 5 - 10

Average Working Interest 85 – 95% 85 – 95%

Production

Annual Net Production (MBoe/d)

% Oil

4Q17 Net Production (MBoe/d)

2017E (Previous)

65 – 71

68 – 73%

78 – 88

2017E (Updated)

67 - 73

67 – 70%

80 - 90

At 2Q17 update:

Increased FY17 and 4Q17 production guidance on stronger well productivity

Adjusted product mix to reflect infusion of acquired vertical production, improved plant efficiencies, increased Wolfcamp C contribution, and broadly higher gas recoveries

Shifted 10 Delaware completions to early 2018

Maintained full-year capital budget

Accelerated spuds offset fewer completions

Quarterly Completion Cadence

Midland Basin Delaware Basin

Capital Allocation (% of 2017E capex) 65 – 70% 30 – 35%

2017E Capital Allocation

2227

30 - 40

40 - 50

1Q17 2Q17E 3Q17E 4Q17EGross Operated Horizontal Completions

Parsley Energy Investment Summary

16


HOWARD

GLASSCOCK

REAGAN

UPTON

MIDLAND

MARTIN

ANDREWS

ECTOR

CRANE

WARD

PECOS

REEVES

LOVING WINKLER

GAINES DAWSON

MITCHELL

STERLING

IRION

Premier acreage in oil windows

Strong financial position

Robust returns

Abundant resource upside

Capital efficient growth

Investment Highlights

17

SUPPLEMENTARY SLIDES

Midland Basin Production Overview

18(1) Includes Parsley completed Midland Wolfcamp A/B and Lower Spraberry wells in core operating area; (2) Includes all Parsley completed Midland Wolfcamp A/B/C and Lower Spraberry wellsin the Midland Basin.

Oil volumes tracking type curve

Gas volumes outpacing type curve

Midland Basin GOR and % Oil Trends(1)

Midland Basin Production vs 1 MMBoe Type Curve

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 180 360 540 720

3-Stream N

et of POP O

il Cut %

GO

R (s

cf/b

bl)

Days of Production

GOR % Oil

Wolfcamp A/B wells showing relatively stable GOR and oil % after initial drawdown period

0

50

100

150

200

250

300

350

400

0 90 180 270 360 450 540 630 720

Cum

ulat

ive

Prod

ucti

on:

Oil

(MBo

) an

dG

as (

MM

scf)

(2)

Days of Production

1MMBOE Gross Oil Midland Basin Actual Oil

1MMBOE Gross Gas Midland Basin Actual Gas

Efficient Midland Basin Drilling

19

Three casing string design proving effective across Midland Basin drilling program

No shift in drilling pace through the San Andres zone

Thick disposal interval and distributed disposal network alleviate pressurization potential

Midland Basin Drill Times(1)

San Andres

Drilling Days

(1) Parsley vertical sections since 4Q16. Excludes wells drilled with pilot hole.

0'

1,000'

2,000'

3,000'

4,000'

5,000'

6,000'

7,000'

8,000'

9,000'

10,000'0 1 2 3 4 5 6 7 8 9 10

Vert

ical

Dep

th

40%

50%

60%

70%

80%

90%

100%

Parsley Energy

Capital Efficient Oil Growth

20

Sources: Bloomberg, FactSet. includes E&P Companies with oil accounting for 40% or more of 2016 production and is comprised of APA, BBG, CLR, CPE, CRC, CRZO, CXO, DNR, DVN, EGN,EOG, EPE, FANG, HES, LONE, LPI, MRO, MTDR, MUR, NFX, NOG, OAS, OXY, PE, PXD, REN, RSPP, SRCI, WLL, and WPX; (1) Production from reported acquisitions/divestitures excluded fromcalculations based on estimated monthly decline of 3%; capital expenditures adjusted for acquisitions of royalty interests where disclosed

2Q17 % Liquids Organic Bo/d Added per $MM Capex – LTM(1)

(60)

(40)

(20)

0

20

40

60

Parsley Energy

Favorable production mix, with high oil/liquids weighting

Top-tier organic oil growth per capex dollar

0

50

100

150

200

250

300

350

0 90 180 270 360 450 540 630 720

Cum

ulat

ive

Prod

ucti

on (

MBo

e)(2

)

Days of Production

Midland S. Delaware

(1) 3-stream; Normalized for downtime; Average IP30s and IP30s per 1,000’ reflect unweighted average of well set; (2) Normalized to 7,000’ stimulated lateral and for downtime; (3) Wells achieving a 30-day IP since 1Q17 quarterly update

Positive Well Performance Trends

Midland Delaware

Wells 22 5

Average Lateral Length 7,730’ 7,090’

30-day IP (Boe/d) 1,245 1,056

30-day IP per 1,000’ (Boe/d) 165 154

% Oil 74% 78%

2Q17 Well Summary(1)(3)

Midland Basin Normalized IP30s Continue to Strengthen(1)

163 167 171180

165

0

50

100

150

200

2H15 1H16 2H16 1Q17 2Q17

IP30

per

100

0' (

Boe/

d)

185*

* Excludes Downspaced Wolfcamp B Wells

Strong well performance in 2Q17 despite high proportion of delineation projects

During 2Q17, the Morgan 25-26-4215H in Upton County set a new company record for highest IP30 in the Wolfcamp A at 2,213 Boe/d

` 21

Expansive, High-quality Drilling Inventory

22

Horizontal Drilling Inventory(1)

(1) As of end 2Q17 pro forma for recently executed acreage trades; Location counts rounded to the nearest ten; (2) Assumes current annual ~130 completion run rate; (3) 16 wells per sectionreflects two landing zones (4) Reflects an average of two landing zones

Extensive inventory of premium drilling locations provides visibility to years of high-return production growth

Operate 93% of net inventory

12+ drilling years of long-lateral, high working interest, operated inventory in Development Zones(2)

Minimum 90% working interest

Minimum 7,500’ lateral length

Abundant inventory upside through increased development density and new target possibilities, including the Jo Mill and Woodford intervals

Nearly 600 net Wolfcamp locations in the Southern Delaware Basin with a low average royalty burden of 15%

GROSS NET WELLS PER SECTION

Development Zones

Midland Basin

Lower Spraberry 1,490 870 8

Wolfcamp A 1,850 1,060 8

Wolfcamp B 3,170 1,890 8 / 16(3)

Wolfcamp C 1,460 920 8

Delaware Basin

Wolfcamp 610 570 16(4)

Development Total 8,580 5,310

Delineation Zones

Midland Basin

Middle Spraberry 1,050 600 5 / 6

Cline 1,900 1,140 8

Atoka 1,450 870 8

Delaware Basin

2nd Bone Spring 160 150 4

3rd Bone Spring 160 150 4

Delineation Total 4,720 2,910

Total 13,300 8,220

Robust Well Economics

23

$40 WTI $60 WTI$50 WTI

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

$3.5

$4.0

$4.5

$5.0

0%

10%

20%

30%

40%

50%

$5.5 MMD&C

$6.0 MMD&C

$6.5 MMD&C

ROR NPV

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

$5.5 MMD&C

$6.0 MMD&C

$6.5 MMD&C

ROR NPV

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

0%

20%

40%

60%

80%

100%

120%

140%

$5.5 MMD&C

$6.0 MMD&C

$6.5 MMD&C

ROR NPV

Current D&C Costs(1)

Type curve-implied returns are strong across oil price spectrum

Actual results are outpacing type curve, translating to even stronger returns on development program

Midland Basin ROR and NPV Sensitivities

Note: Economics based on 1 MMBoe type curve; NGL price 40% of WTI; Gas $3/Mcf; (1) Based on 7,000’ stimulated lateral

Efficient Reserve Growth

24

YE16 proved reserves up 80% Y/Y (oil up 85% Y/Y) despite writing off remaining ~18 MMBoe of vertical PUD reserves

Strong organic reserve replacement ratio of approximately 680%(2)

PD F&D down 70% Y/Y to $8.04/Boe(3)

Strong Growth in Proved Reserves

Tota

l Pro

ved

Rese

rves

(M

MBo

e)

Oil (MMBbl)

Gas(Bcf)

NGL (MMBbl)

Total (MMBoe)

PDP 59.3 121.8 23.7 103.3

PDNP 1.9 2.2 0.6 2.8

PUD 75.4 99.7 24.2 116.2

Total Proved 136.6 223.7 48.5 222.3

124

-14 -4 -7

24

99

222

-50

0

50

100

150

200

250

YE15 Prod. Rev. Divest. Acq. Adds YE16

(1) Source: SGS E&P Comp Sheets – Week Ending June 23, 2017. Companies include APA, APC, AR, BBG, CDEV, CHK, CLR, COG, CPE, CRK, CRZO, CXO, DNR, DVN, ECA, ECR, EGN, EOG,EPE, EQT, FANG, GPOR, HES, HK, JAG, JONE, LPI, MRO, MTDR, NBL, NFX, NOG, OAS, OXY, PDCE, PE, PXD, QEP, REN, RICE, RRC, RSPP, SD, SGY, SM, SN, SRCI, SWN, SWTF, UNT, WLL,WPX, WTI, XCO, XEC, and XOG. Oily E&P Companies are defined as companies with 2016 percent oil of 40% or greater, and Gassy E&P Companies are defined as companies with 2016 percentoil of less than 40%; (2) Organic reserve replacement ratio calculated as total 2016 reserves additions and revisions (technical and pricing) divided by total 2016 production; excludesacquisitions and divestitures; (3) PD F&D calculated as total 2016 Capex (including Infrastructure and Other) divided by total 2016 proved developed reserves additions and revisions (technicaland pricing); excludes acquisitions and divestitures; (4) Reserve summary as of 12/31/2016 and audited by NSAI; Data for Parsley only; not pro forma for pending acquisitions

Proved Reserves Summary(4)

+80%

$0

$5

$10

$15

$20

$25

$30

$35

$40

PD F&D ($/Boe) Ranks Highly among Oily E&Ps(1)


Parsley Energy

Substantial Oil Hedge Position

25

Hedge positions as of 8/24/2017; (1) When the NYMEX price is above the put price, Parsley receives the NYMEX price. When the NYMEX price is between the put price and the short put price,Parsley receives the put price. When the NYMEX price is below the short put price, Parsley receives the NYMEX price plus the difference between the short put price and the put price;(2) Functions similarly to put spreads except that when the index price is at or above the call price, Parsley receives the call price; (3) Premium realizations represent net premiums paid(including deferred premiums), which are recognized as income or loss in the period of settlement; (4) When the NYMEX price is above the call price, Parsley receives the call price. When theNYMEX is below the put price, Parsley receives the put price. When the NYMEX price is between the call and put prices, Parsley receives the NYMEX price; (5) Parsley receives the strike price;(6) Parsley receives the swap price

3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 1Q19 2Q19 3Q19 4Q19

Put Spreads (MBbls/d)1 35.7 45.5 38.3 37.9 42.4 45.7 6.7 6.6

Put Price ($/Bbl) $51.23 $50.96 $51.74 $51.09 $49.52 $49.55 $50.00 $50.00

Short Put Price ($/Bbl) $41.14 $41.43 $41.09 $41.09 $39.52 $39.55 $40.00 $40.00

Three Way Collars (MBbls/d)2 21.7 28.0 31.0 31.0 8.3 8.2 8.2 8.2

Short Call Price ($/Bbl) $68.85 $70.79 $75.65 $75.65 $80.40 $80.40 $80.40 $80.40

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

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

Premium Realization ($MM)3 ($8.3) ($14.6) ($21.2) ($19.6) ($16.7) ($18.0) ($4.2) ($4.2) ($1.5) ($1.5)

Collars (MBbls/d)4 4.0 4.0 3.0 3.0 3.0 3.0

Short Call Price ($/Bbl) $59.73 $59.98 $61.31 $61.31 $61.31 $61.31

Put Price ($/Bbl) $46.75 $46.75 $45.67 $45.67 $45.67 $45.67

Swaps (MBbls/d)5 0.5 0.5 0.5 0.5 0.5 0.5

Strike Price ($/Bbl) $55.00 $55.00 $55.00 $55.00 $55.00 $55.00

Total MBbls/d Hedged 40.2 50.0 63.5 69.4 76.9 80.1 15.0 14.8 8.2 8.2

Mid-Cush Basis Swaps (MBbls/d)6 16.7 16.7 9.8 9.8 9.7 9.7

Swap Price ($/Bbl) ($1.00) ($1.00) ($0.92) ($0.92) ($0.92) ($0.92)

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