INVESTOR PRESENTATION3Q »2017
SEPTEMBER 25, 2018
Q2 2019Earnings Presentation
August 7, 2019
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.
3
Parsley Energy Overview
► Tightened 2019 capital budget range
► Raised 2019 capital efficiency target
► Positioned for free cash flow inflection
► Defended operational efficiency gains
► Economies of scale and core inventory depth
► Elite return profile
► Efficient and sustainable growth
► Advantaged production flow and pricing
► Margins enhanced by minerals ownership
► Financial flexibility with strong balance sheet
ANDREWS
MARTIN
ECTOR
LEA
WINKLER
WARD
CRANE
REEVESPECOS
UPTON
MIDLAND
GLASSCOCK
REAGAN
HOWARD
DelawareBasin
CentralBasin
Platform
MidlandBasinPremier Permian Pure-Play
2Q19 Highlights
NYSE Symbol: PEMarket Cap: $4,484 MM Net Debt: $2,157 MMEnterprise Value: $6,641 MMShare Count: 317 MM
Market Snapshot(3)
Permian Basin Net Net Leasehold Acreage: ~189,000(1)
(96% Operated)Midland Basin: ~147,000Delaware Basin: ~42,000
Net Royalty Acreage: ~7,500Standardized Royalty Acreage (12.5% NRI): ~60,000(2)
Parsley Energy Acreage
Parsley Acreage
(1) As of 6/30/2019 pro forma for scheduled 2019 acreage expirations recorded in 4Q18; (2) Parsley’s ~7,500 net royalty acres are shown on a 100% NRI basis. If Parsley’s royalty ownership is standardized to a 12.5%, or 1/8th, royaltyinterest, Parsley’s net royalty acreage would equate to approximately 60,000 net royalty acres; (3) Market capitalization calculated using fully diluted share count of 317 MM shares (281 MM Class A shares plus 36 MM Class B shares)as of 8/6/2019 and closing price as of 8/5/2019. Net debt as of 6/30/2019. Net Debt is a non-GAAP financial measure defined as total debt less cash and cash equivalents. Enterprise Value is calculated as market capitalization plus 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.
Defend and extend operational efficiency gains
Increase footage drilled/completed per rig/crew over FY18 levels
1H19 footage drilled/completed per rig/crew has increased 13/15% from FY18 levels
Work with high-performing service partners on pricing and contracting
Improve capital efficiency by 8-10%+ YoY(1)
Tracking ahead of plan; targeting 12-14%+ YoY improvement in capital efficiency
Hedge to protect cash flow and balance sheet while retaining oil price upside
Outspend by less than $250 million in any oil price environment(2)
Methodical additions to 2020 oil hedges
Sustain culture that promotes and prioritizes community stewardship
Collaborate with Permian Strategic Partnership (“PSP”); publish Sustainability Report by year-end 2019
PSP initiatives in motion; established Nominating, Environmental, Social, & Governance Board Committee
Rate of Return (“ROR”)-driven approach to well selection
Improve capital efficiency by 8-10%+ YoY(1)
Tracking ahead of plan; targeting 12-14%+ YoY improvement in capital efficiency
Accelerate timeline to self-funded growth Outspend by less than $250 million in any oil price environment(2)
1H19 outspend of $178MM; expect to generate free cash flow in 2H19(2)(3)
Further increase visibility onmanagement and shareholder alignment
Addition of corporate returns metric to 2019 incentive plan Added CROCI to 2019 incentive plan(4)
Leverage legacy water infrastructure investments
Increase 3rd party water revenues and/or explore strategic alternatives
Strategic review ongoing; expect decision by YE19
Exercise patience on incremental crude transport agreements
Deliver healthy long-term realized oil prices while limiting minimum volume commitments
Dependable flow assurance, diversified pricing, and tight API gravity range (41°average) translating to favorable realized oil prices
4
Delivering on 2019 Action Plan
Discipline
Guiding Principles
Foresight
Stability
2019 Action Plan Accountability Progress through 2Q19
(1) Capital efficiency calculated as barrels of organic oil production added (Q41/Q40, adjusted for proved developed producing (“PDP”) oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDPoil base decline of ~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed after 9/30/2018; (2) Free cash flow (outspend) is a non-GAAP financial measure and is defined as cash flow from operationsbefore changes in operating assets and liabilities less accrual-based development capital expenditures. For the reconciliation of free cash flow (outspend) please see the Supplementary Slides; (3) Based on strip prices as of 8/2/2019;(4) Disclosed in definitive proxy statement for 2019 annual meeting (filed with SEC on April 8, 2019). Cash return on capital invested (“CROCI”) is calculated by dividing the sum of the Company’s cash flow from operations and after-taxinterest expense by the sum of the Company’s average gross property, plant and equipment and average non-cash working capital.
5
Boosting Capital Efficiency Target
8-10%+
12-14%+
1-2%
4%
4%
4-5%
Original Capital Efficiency Target (4Q18)
3-4%
4-5%
► Combination of upsized fracs, wider spacing and compressed stage tests
► Longer laterals, more local sand, fewer new-build facilities
► Higher concentration of activity in Martin, Midland, and Upton Counties
Optimized Completions
Shifting Activity Mix
Capex Savings
► Encouraging early-time results validating shift in approach
► Cycle time improvement, well design tweaks, and reduced consumables costs
► Confirmatory strong well results in Martin, Midland, and Upton Counties
Optimized Completions
Shifting Activity Mix
Capex Savings
Adding More Barrels of Oil for Fewer Development Dollars
► 2019 Action Plan designed to improve capital efficiency and compress timeline to sustainable free cash flow Expected 8-10%+ YoY improvement driven by lower well costs, high-graded activity, and optimized completions Raising targeted YoY improvement to 12-14%+ after encouraging results in the first half of 2019
Cap
ital E
ffici
ency
Impr
ovem
ent (
YoY%
)(1)
Updated Capital Efficiency Target (2Q19)
(1) Capital efficiency calculated as barrels of organic oil production added (Q41/Q40, adjusted for PDP oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed after 9/30/2018.
YE18PDP Oil Base Decline(4)
50%
45%
40%
35%YE17 YE19E 2020-2021E
20
25
30
35
40
45
50
PE
Hor
izon
tal P
erm
ian
Wel
l Vin
tage
(A
vera
ge M
onth
s Pr
oduc
ing)
► 2019 Action Plan designed to improve capital efficiency and compress timeline to sustainable free cash flow
Targeting free cash flow in 2H19(1) despite younger asset base than most peers
Maturing asset base coincides with a moderating base decline
Maintenance capital becomes a smaller burden on future discretionary cash flow (“DCF”)(2)
Improving free cash flow sustainability increases visibility for return of capital to shareholders
6
Building to Sustainable Free Cash Flow –Maturing Asset Base
(1) Free cash flow is a non-GAAP financial measure and is defined as cash flow from operations before changes in operating assets and liabilities less accrual-based development capital expenditures. Based on strip pricing as of8/2/2019; (2) Maintenance capital is defined as the capital expenditures required to maintain fourth quarter oil production levels for one year. DCF is a non-GAAP financial measure and is defined as cash flow from operations lesschanges in working capital; (3) DrillingInfo. Includes all horizontal wells placed on production after 1/1/2012. Peers include CVX, CXO, EOG, FANG, OXY, PXD, and XOM; (4) Refers to Q41/Q40 PDP oil base decline; (5) Maintenancecoverage ratio is calculated as DCF divided by maintenance capital.
Asset Base Maturity forPermian Operators of Scale(3)
An Organic Path to a Lower Maintenance Capital Burden
► Achieved scale with significant activity ramp
► 65% oil production CAGR
2017-2018 Development
Younger Asset Base
► Steeper base decline
2017-2018 Development
Maintenance Capex was larger burden on DCF(2)
► Moderating base decline► Nearly 25% organic oil growth YoY
2019 Action Plan
Maintenance Capex expected to be smaller burden on future DCF(2)
100%2017-2018 2019E 2020-2021E
Maintenance Coverage Ratio(5)
Peers
400
500
600
700
800
900
1,000
1,100
1,200
1,300
1,400
2017 2018 1Q19 2Q19
Feet
Drilled Feet per Operational Day per Rig
Stimulated Lateral Feet per Operational Day per Crew
7
Defend and Extend Efficiency Gains
(1) Operational days measured as days equipment is active. Does not include mobilization or other idle time; (2) “Drilling efficiency” is measured based on drilled feet per operational day.
(1)
(1)
Maintaining Operational Momentum 2Q19 Efficiency Highlights
1H19 Drilling: +13% from 2018 average1H19 Completions: +15% from 2018 average Drilling
► Sustained drilling efficiency gains with ~8% improvement as compared to 1Q19(2)
Enables drop from 12 to 11 development rigs for 2H19
► Shorter cycle times reduce costs
A one day reduction in drill time can translate to ~$60,000 in well cost savings
Completions
► Maintained high level of efficiency despite sequential increase in upsized fracs and compressed stage tests
Expect three-to-four high-quality completion crews running in 2H19
► Proactively managing schedule to adhere to capital budget and preserve operational momentum into 2020
Targeting consistent capital investment pace to minimize friction costs
0
20
40
60
80
100
120
140
160
180
0 90 180 270 360
Cum
ulat
ive
Oil
Prod
uctio
n (M
Bo)
Days on Production
2018 POPs 1H19 POPs
Development Across Acreage PositionImproving Upton Well Performance(1)
► Recent Upton County well results highlight early success from ROR-focused development program Completion design changes facilitating a 9% improvement versus 2018 Upton wells
8
Operational Spotlight – Upton County
(1) Normalized to 10,000’ lateral length and adjusted for downtime; (2) Wells placed on production.
1H19 wells outperforming 2018 wells by 9%
Parsley Acreage2018 Pads1H19 Pads
(2)
Reese
Leo
Hanks Family
MIDLAND
UPTON
ROR-Focused Development Highlights
Lease NameProject
SizeAverage IP30
(Boe/d/1k’) % Oil
Leo 2 wells 219 74%
Hanks Family 3 wells 205 74%
Reese 5 wells 154 78%(2)
9
Building to Sustainable Free Cash Flow –Advantaged Marketing Position
(1) Certain sales contracts contingent on pipeline start-up dates, assumptions for which are based on most recent public disclosure; (2) Peers include CDEV, CPE, CXO, FANG, HK, JAG, LPI, MTDR, and SM; Permian realizations usedwhere applicable; (3) IHS. Horizontal wells only; (4) West Texas Light (WTL) Midland is defined as crude with an API gravity between 44.1° and 49.9° with a sulphur content less than 0.40%. West Texas Sour (WTS) is defined as crudewith an API gravity between 30.0° and 38.0° with a sulphur content less than 2.50%.
► Parsley aims to insulate cash flow from regional oil price dislocations through proactive diversification
Delivered peer-leading oil realizations during tight takeaway market in 2018
Sales contracts provide exposure to MEH, Brent and Midland benchmarks in 2019-2020(1)
Broad portfolio marketing approach mitigates takeaway risk associated with an individual pipeline or port
Leading Oil Price Realizations
$50$51$52$53$54$55$56$57$58$59$60
PE
1Q18
-1Q
19 U
nhed
ged
Oil
Pric
e R
ealiz
atio
n ($
/Bo)
Peers(2)
Marketing strategy centered around two guiding principles: dependability and diversification
► Favorable oil quality with tight API gravity range across acreage footprint Produced oil volumes register a weighted average
API gravity of ~41° Sales volumes not subject to WTL or WTS discounts(4)
Permian API Gravity Sweet Spot(3)
Parsley Acreage<40° API Gravity40-42°42-44°
44-47°47-50°50°+
ANDREWS
ECTOR
HOWARD
MARTIN
MIDLAND
GLASSCOCK
REAGAN
UPTON
CRANE
PECOS
REEVES
WARD
WINKLER
LEA
EDDY
LOVING
MIDLAND BASIN
CENTRALBASIN
PLATFORM
DELAWAREBASIN
40%
45%
50%
55%
60%
65%
70%
75%
80%
85%
$7
$8
$9
$10
$11
$12
$13
$14
$15
$16
2015 2016 2017 2018 1Q19 2Q19
Operating C
ash Margin (%
)
Per
-Uni
t Ope
ratin
g C
osts
($/B
oe)
Per-Unit Operating Costs ($/Boe) Operating Cash Margin (%)
10
Building to Sustainable Free Cash Flow –Compressing Costs to Expand Margins
(1) Per-unit operating costs include lease operating expenses, cash based general and administrative expenses (exclusive of stock-based compensation), and production and ad valorem taxes. Transportation and processing costs areexcluded from 2018 and 2019 to normalize for the period over period impacts of adopting ASC 606; (2) Operating cash margin percentage is a non-GAAP financial measure. For a reconciliation of operating cash margin to the mostdirectly comparable GAAP financial measure, please see the Supplementary Slides. Operating cash margin percentage calculated as operating cash margin per Boe divided by realized price per Boe excluding hedges. Operating cashmargin defined as realized price per Boe excluding hedges less per-unit operating costs including transportation and processing costs; (3) Peers include CDEV, CPE, CXO, FANG, JAG, PXD, and WPX.
Operating Cash Margin Expansion Peer-Leading LOE Trend
$2.50
$3.50
$4.50
$5.50
$6.50
$7.50
$8.50
2015 2016 2017 2018 1Q19 2Q19
Leas
e O
pera
ting
Exp
ense
s ($
/Boe
)
Parsley Energy Peers
► Extracting more value per barrel of production through stringent cost control and scale benefits
Delivered company-record LOE per Boe and cash G&A per Boe during 2Q19
► Vigilant focus on costs helps support sustainable free cash flow profile
Teams incentivized to defend peer-leading LOE targets
Right-sized organization with 8% reduction in workforce since YE18
(3)(1) (2)
0
3
6
9
12
15
0
30
60
90
120
150
Net
Oil
Pro
duct
ion
(MB
o/d)
Net S
tandardized Royalty A
cres (000's)
Net Oil Production (MBo/d) Net Standardized Royalty Acres (000's)
► Minerals ownership enhances Parsley’s sustainable free cash flow profile
Adds high margin production without any associated capex or operating expenses
Surface ownership can generate secondary cash flow stream, offering additional upside
High degree of Parsley operatorship improves visibility of development and cash flow timing
► Growing number of public mineral companies provides more valuation markers for asset class
Parsley Minerals Ownership
11
Building to Sustainable Free Cash Flow –Minerals Ownership
(1) Public filings. Peers include FLMN, MNRL, and VNOM; (2) Market capitalization for peers calculated using closing price as of 8/2/2019 and is not pro forma for pending transactions; (3) 2Q19 oil production attributable to Parsley’sminerals ownership. Peer production period based on latest reported quarterly figures and is not pro forma for pending transactions; (4) Royalty ownership standardized to a 12.5%, or 1/8th, royalty interest and is not pro forma forpending transactions.
Market Cap(2)
Comparable Public Minerals Companies
Net Standardized Royalty Acreage: ~60,000(4)
Midland Basin: ~13,000(4)
Delaware Basin: ~47,000(4)
► 100% Permian exposure ► 86% Parsley-operated
Net Surface Acreage: ~37,000
Parsley AcreageParsley Minerals Ownership
Minerals Summary
MARTIN
ECTOR
WINKLER
WARD
CRANE
REEVES PECOS
UPTON
MIDLAND
GLASSCOCK
REAGAN
HOWARD
DelawareBasin
CentralBasin
Platform
MidlandBasin
(3) (4)
PermianPure-Play
Peer Exposure to Permian
High Low
$4.3B $1.0B $0.7B
PE Minerals Peers(1)
Senior Notes ($MM)
2019 2020 2021 2022 2023 2024 2025 2026 2027
Favorable Debt Maturity Schedule
Ample Borrowing Capacity
12
Strong, Flexible Financial Position
Committed Amount
Remaining Borrowing
Base
1H25
2H25
$1,100
$2,700
► Ample liquidity of ~$1.0 billion(1)
► Healthy leverage ratio of 1.6x(2) LTM Adj. EBITDAX
(1) As of 6/30/2019. Calculated as committed portion of revolving credit agreement, net of letters of credit, plus cash and cash equivalents; (2) Leverage ratio calculated as Net Debt divided by last twelve-month Adjusted EBITDAX. NetDebt is defined as total debt less cash and cash equivalents at 6/30/2019. Net Debt and Adjusted EBITDAX are non-GAAP financial measures. For a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the mostdirectly comparable GAAP financial measure, please see the Supplementary Slides.
► Favorable debt maturity schedule withearliest notes maturity in 2024
► Weighted average cost of debt has dropped~250 bps since mid-2016
► Credit rating upgrades from both Moody’s andStandard & Poor’s in 1H19
► Proactively adding 2020 hedges, including new Brentcontracts that further align positions with regional priceexposure
$0.0
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
YE14 YE15 YE16 YE17 YE18 2Q19
Bor
row
ing
Bas
e ($
B)
Borrowing base has more than quadrupled in last four years
$1,000$400
$700$450
$650
Revolving Credit Facility ($MM)
► Tightening 2019 capital budget range
► Progressing toward sustainable free cash flow in 2H19(2)
► Increasing targeted YoY improvement in capital efficiency to 12-14%+(3)
► Raising organic oil growth guidance to nearly 25% YoY(4)
► Lowering unit operating cost guidance by 9% at the midpoint
► Efficiency gains allowing for more footage with less equipment
Expect to carry operational momentum into 2020
0
10
20
30
40
50
60
70
80
90
0
2
4
6
8
10
12
14
16
18
1Q14
2Q14
3Q14
4Q14
1Q15
2Q15
3Q15
4Q15
1Q16
2Q16
3Q16
4Q16
1Q17
2Q17
3Q17
4Q17
1Q18
2Q18
3Q18
4Q18
1Q19
2Q19
3Q19
E4Q
19E
Net O
il Production (M
Bo/d)
Hor
izon
tal R
ig C
ount
Horizontal Rigs Net Oil Production (MBo/d)
Prior 2019 Guidance
Updated 2019 Guidance
Production
Net Oil Production (MBo/d) 80.0 - 85.0 85.0 - 86.5
Net Production (MBoe/d) 124.0 - 134.0 134.0 - 139.0
Capital Program
Total Development Expenditures ($MM) $1,350 - $1,550 $1,400 - $1,490
Drilling & Completion (% of Total) ~85% ~85%
Facilities, Infrastructure & Other (% of Total)
~15% ~15%
Activity
Gross Operated Horizontal POPs(1) 130 - 140 135 - 140
Midland Basin (% of Total) ~85% ~85%
Delaware Basin (% of Total) ~15% ~15%
Average Lateral Length 10,000’ - 10,500' 10,100’ - 10,500'
Gross Operated Lateral Footage (000's) 1,350' - 1,470' 1,365' - 1,470'
Average Working Interest ~90% 93 - 94%
Units Costs
Lease Operating Expenses ($/Boe) $3.50 - $4.50 $3.40 - $3.90
Cash G&A ($/Boe) $2.75 - $3.25 $2.60 - $2.90
Production & Ad Valorem Taxes (% of Total Revenue)
6% - 7% 6% - 7%
13
Guidance Summary
All guidance as of 8/6/2019. (1) Wells placed on production; (2) At strip prices as of 8/2/2019. Free cash flow is a non-GAAP financial measure. Free cash flow is defined as cash flow from operations before changes in operating assetsand liabilities less accrual-based development capital expenditures; (3) Capital efficiency calculated as barrels of organic oil production added (Q41/Q40, adjusted for PDP oil base decline) per million dollars of development capitalexpenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed after 9/30/2018; (4) Adjusted for divestitures closed in 2018.
3Q19 Guidance87-90 MBo/d
Continuing to budget at $50 WTI
Delivering on 2019 Development Plan
CLICK TO ADD TEXT
• SUPPLEMENTARY
SLIDESSUPPLEMENTARY SLIDES
Supplementary Slides
15
Hedge Position
► Methodical, consistent approach
► Protect cash flow stream in weaker oil price environment
► Preserve meaningful upside exposure in stronger oil price environment
► Align hedges with regional price exposure
Hedge positions as of 8/6/2019. Prices represent the weighted average price of contracts scheduled for settlement during the period; (1) When the reference price (WTI, Midland, MEH, Brent, or Henry Hub) is above the long put price,Parsley receives the reference price. When the reference price is between the long put price and the short put price, Parsley receives the long put price. When the reference price is below the short put price, Parsley receives thereference price plus the difference between the short put price and the long put price; (2) Functions similarly to put spreads except when the reference price is at or above the call price, Parsley receives the call price; (3) When thereference price (WTI) is above the call price, Parsley receives the call price. When the reference price is below the long put price, Parsley receives the long put price. When the reference price is between the short call and long putprices, Parsley receives the reference price; (4) Premium realizations represent net premiums paid (including deferred premiums), which are recognized as a loss in the period of settlement.
Open Crude Oil Derivatives Positions
Open Natural Gas Derivatives Positions
Hedging Strategy3Q19 4Q19 1Q20 2Q20 3Q20 4Q20OPTION CONTRACTS
CUSHING
Put Spreads – Cushing (MBbls/d)(1) 19.6 19.6 Long Put Price ($/Bbl) $57.29 $57.29
Short Put Price ($/Bbl) $47.29 $47.29
Three Way Collars - Cushing (MBbls/d)(2) 26.1 26.1 Short Call Price ($/Bbl) $72.69 $72.69
Long Put Price ($/Bbl) $51.88 $51.88
Short Put Price ($/Bbl) $42.81 $42.81
Collars – Cushing (MBbls/d)(3) 21.2 21.2 Short Call Price ($/Bbl) $58.26 $58.37
Long Put Price ($/Bbl) $54.50 $54.56
MIDLAND
Put Spreads – Midland (MBbls/d)(1) 4.9 4.9 Long Put Price ($/Bbl) $60.00 $60.00
Short Put Price ($/Bbl) $50.00 $50.00
Three Way Collars - Midland (MBbls/d)(2) 4.9 4.9 6.7 6.6 Short Call Price ($/Bbl) $64.65 $64.65 $77.50 $77.50
Long Put Price ($/Bbl) $50.00 $50.00 $61.25 $61.25
Short Put Price ($/Bbl) $45.00 $45.00 $51.25 $51.25
MAGELLAN EAST HOUSTON ("MEH")
Put Spreads – MEH (MBbls/d)(1) 4.9 4.9 5.0 4.9 Long Put Price ($/Bbl) $60.00 $60.00 $70.00 $70.00
Short Put Price ($/Bbl) $50.00 $50.00 $60.00 $60.00
Three Way Collars - MEH (MBbls/d)(2) 3.3 3.3 36.7 36.3 19.6 19.6 Short Call Price ($/Bbl) $75.00 $75.00 $75.98 $75.98 $76.63 $76.63
Long Put Price ($/Bbl) $60.00 $60.00 $59.57 $59.57 $58.79 $58.79
Short Put Price ($/Bbl) $50.00 $50.00 $49.58 $49.58 $48.79 $48.79
BRENT
Three Way Collars - Brent (MBbls/d)(2) 8.2 8.2 8.2 Short Call Price ($/Bbl) $75.00 $75.00 $75.00 Long Put Price ($/Bbl) $62.40 $62.40 $62.40 Short Put Price ($/Bbl) $52.40 $52.40 $52.40
Total Option Contracts (MBbls/d) 84.8 84.8 48.4 56.0 27.8 27.8
Premium Realization ($MM)(4) ($11.8) ($11.8) ($12.2) ($12.6) ($6.9) ($6.9)
3Q19 4Q19OPTION CONTRACTS
HENRY HUB
Three Way Collars - Henry Hub (MMBtu/d)(2) 32,609 32,609 Short Call Price ($/MMBtu) $3.93 $3.93
Long Put Price ($/MMBtu) $3.00 $3.00
Short Put Price ($/MMBtu) $2.50 $2.50
Total Option Contracts (MMBtu/d) 32,609 32,609
Leverage legacy water infrastructure investments
Increase 3rd party water revenues and/or explore strategic alternatives
Exercise patience on incremental crude transport agreements
Deliver healthy long-term realized oil prices while limiting minimum volume commitments (MVCs)
Rate of Return (“ROR”)-driven approach to well selection
Improve capital efficiency by 8-10%+ YoY(1)
Accelerate timeline to self-funded growth
Outspend by less than $250 million in any oil price environment(2)
Further increase visibility on management and shareholder alignment
Addition of corporate returns metric to 2019 incentive plan
Defend and extend operational efficiency gains
Increase footage drilled/completed per rig/crew over 2018 levels
Work with high-performing service partners on pricing and contracting
Improve capital efficiency by 8-10%+ YoY(1)
Hedge to protect cash flow and balance sheet while retaining oil price upside
Outspend by less than $250 million in any oil price environment(2)
Sustain culture that promotes and prioritizes community stewardship
Collaborate with Permian Strategic Partnership; publish Sustainability Report by year-end 2019
16
Setting the Course for 2019 & Beyond –Unveiled February 2019
Discipline
Guiding Principles provided foundation…
Foresight
Stability
For an optimal2019 Action Plan
And Accountabilitywill help achieve goals and…
Compelling Long-Term Targets
Health, Safety, & Environmental
Excellence
Top-Tier Corporate Returns
Increasing Free
Cash Flow
Differentiated Cash Flow
Growth per Share
(1) Capital efficiency calculated as barrels of organic oil production added (Q41/Q40, adjusted for PDP oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of ~45% and4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed in 4Q18; (2) Outspend is a non-GAAP financial measure and is defined as cash flow from operations before changes in operating assets and liabilities lessaccrual-based development capital expenditures.
► Proactive build-out of water infrastructure network with $165 million of cumulative capital investment
Permitted disposal capacity provides ample running room for future growth
Water A&D Activity Picking UpRobust Water Infrastructure Network
17
Water Asset Overview
Water Management Statistics Company-Wide
Total Salt Water Disposal (“SWD”) Permitted Volume (Bbl/d)(1) 1.5 million
Percent of Produced Water Transported by Pipeline 95%
Surface Acres 37,000
► Strategic review ongoing; expect decision by YE19
► Reduce water infrastructure capital expenditures YoY
► Increase revenue from third party water volumes
2019 Action Plan
Date Buyer Seller Description
5/1/2019 PrivateCompany PDC Energy 82 miles of pipeline and 7 SWDs with 180 MBbls/d of permitted
capacity in Reeves and Culberson counties
3/11/2019 PrivateCompany
PrivateCompany
50 SWDs and 420 miles of water gathering and transport pipelines and 1.4 million barrels of permitted disposal capacity
1/3/2019 Private Company
Concho Resources
100% interest in 3 SWDs with 44 miles of gathering pipeline in Southern Delaware
12/20/2018 Private Company
NGL Energy Partners
9 SWDs and associate pipelines along with additional permits in Southern Delaware
11/8/2018 Western Gas Partners
Anadarko Petroleum
17 SWDs with 505 MBbls/d capacity and 620 miles of gathering pipelines in Delaware Basin
10/31/2018 Private Company
HalcónResources
All water facilities including gathering lines, SWDs, freshwater wells, and recycling facilities
Parsley Energy AcreageParsley Energy SWD(1)
Delaware Basin
1
2
3
3
4
6
6Delaware
Basin
MidlandBasin
PECOS
REEVES
WARD
MARTIN
HOWARD
GLASSCOCK
REAGANUPTON
MIDLAND
Midland Basin
5
4
55
(1) Includes existing and permitted operated SWDs.
2
2
2
2
5
6
1
► Outpacing top quartile operators in key value drivers highlights Parsley’s competitive advantage
Sustained by low-cost, durable asset base and top-tier operational ability
► Focus remains fixed on return of each incremental dollar invested
Significant insider ownership enables participation in value creation alongside public shareholders
Operators with Top Quartile Valuation(8) Parsley Energy
Average Rank of Operators with Top Quartile Valuation(8)
Average Rank of Operators with Bottom Quartile Valuation(8)
Operators with Interquartile Valuation(8)
Operators with Bottom Quartile Valuation(8)
Recycle Ratio(2)(7)
18
Establishing a Competitive AdvantageAmong Independent E&Ps
(1) Seaport Global Securities E&P Comps as of 7/29/2019. 1Q19 operating margin as defined by Seaport Global Securities. Operating margin is a non-GAAP financial measure; (2) Seaport Global Securities E&P Comps as of7/29/2019. Recycle ratio is equal to 1Q19 operating margin divided by 2018 PD F&D. PE recycle ratio includes actual 2018 PD F&D/Boe of $11.63. For definitions of PD F&D and Recycle ratio, please see slide 26; (3) FactSet. Basedon 1Q19 reported production; (4) DrillingInfo as of 8/2/2019; (5) FactSet; 2018 Debt-adjusted discretionary cash flow per share growth. Debt-adjusted discretionary cash flow per share is equal to discretionary cash flow divided by debt-adjusted shares. Discretionary cash flow is equal to cash flow from operations less changes in working capital. The number of debt-adjusted shares is equal to the number of fully diluted shares plus total debt minus cash divided byaverage share price in the period; (6) Bloomberg. Total value ($) of executive officer and director ownership; (7) Peers include APA, AR, AXAS, CDEV, CHK, CLR, CNX, COG, CPE, CRZO, CXO, DVN, ECA, EOG, EPE, EQT, ESTE,FANG, HES, JAG, LPI, MRO, MTDR, MUR, NBL, OAS, OXY, PDCE, PXD, QEP, RRC, SM, SRCI, SWN, WLL, WPX, XEC, and XOG; (8) Valuations from FactSet as of 8/2/2019 and defined as enterprise value divided by consensus2019 EBITDAX estimate.
OperatingMargin(1)(7) % Oil(3)(7)
Debt-Adjusted DCF/Share Growth(5)(7)
Horizontal Rigs in Lower-48(4)(7)
Rel
ativ
e R
ank
InsiderOwnership(6)(7)
Commodity Weighting Scale & Accretive Growth Aligned
InterestsAsset Quality
& Operational Efficiency
19
Organic Path to Self-Funded Growth
(1) Free cash flow is a non-GAAP financial measure. Free cash flow is defined as cash flow from operations before changes in operating assets and liabilities less accrual-based development capital expenditures; (2) At strip prices asof 8/2/2019; (3) Capital efficiency calculated as barrels of organic oil production added (Q41/Q40, adjusted for PDP oil base decline) per million dollars of development capital expenditures. Assumes 4Q18/4Q17 PDP oil base decline of~45% and 4Q19/4Q18 PDP oil base decline of ~43%. Adjusted for divestitures closed after 9/30/2018.
Productivity Improvements
► Optimizing completions
Increasing average
proppant loading
10-15% YoY
Wider spacing in
select targets
Compressed stage
follow-up trials
► Shifting mix to northern
Midland Basin
Accelerating Free Cash Flow by Prioritizing ROR Boosting Capital Efficiency
Expected Capex Savings
► Lower service and
equipment costs
► ~15% increase in
average lateral length
► ~75% of proppant
sourced from regional
sand mines
► Fewer new-build
facilities; more
add-ons
2019 Action Plan targets 12-14%+ YoY increase
in capital efficiency(3)
ROR
Increasing Density
(Wells / Section / Bench)
Free Cash Flow Timing(1)(2)
2019 Action Plan
2017-2018 Development Approach
1H20
Inventory depth enables shift in development approach
ROR focus pulls forward timing of sustainable free cash flow(1)
2H19
20
Long Reinvestment Runway Provides Development Optionality
(1) Leasehold where Parsley can drill or propose drilling horizontal wells with lateral lengths equal to or greater than 1-mile; (2) As of 6/30/2019 pro forma for 2019 acreage expirations recorded in 4Q18;(3) Development inventory includes operated locations in Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones in defined DSUs. Darker shade of blue represents actual 2018 development program;(4) Based on 2019E activity levels in each development area; (5) Bottom of inventory range represents development of inventory in defined DSUs utilizing increased proppant and wider spacing configuration, consistent with 2019development approach and is comprised of 26 million gross (22 million net) lateral feet in proven formations (Lower Spraberry, Wolfcamp A, Wolfcamp B, and Wolfcamp C zones). Top of inventory range represents full developmentinventory in defined DSUs and is comprised of 35 million gross (30 million net) lateral feet in proven formations.
MARTIN
HOWARD
MIDLAND
GLASSCOCK
REAGAN
UPTON
REEVESPECOS
CentralBasin
Platform
► Durable, geographically balanced inventory enables shift to a more ROR-focused development approach in 2019
Higher concentration of activity in Martin, Midland, and Upton Counties
Combination of upsized fracs and wider spacing in select areas
Over a decade of running room in each distinct core geography at 2019 development patterns
WARD
Development Inventory Drilled(1)
2019E Development Program(2)
Inventory Life at 2019E Pace(3)ANDREWS
ECTOR
CRANE
2019 Action PlanParsley Drill Spacing Unit (“DSU”)(1) Other Parsley Acreage
(167,000 net acres)(2) (22,000 net acres)(2)
DSU Development Inventory Drilled(3)
2018 DSU Development Program(3)
2019E Development Program(4)
Remaining DSU Inventory Life at 2019E Pace(4)(5)
► Geographically balanced program
► Emphasis on resource discovery and delineation
2017-2018 Development Approach
HOWARD
0
5
10
15
20
25
Ope
rato
r Cou
nt
Permian Scale Sweet Spot
21
► Efficient allocation of capital within the Permian requires sufficient scale► Parsley believes optimal scale both retains corporate agility and ensures a voice in service market
Voi
ce in
Mar
ket
Cor
pora
te A
gilit
y
Limited
Small-Scale Optimal ScaleMidstream: Sizable acreage position and growth visibility helped lock in
favorable terms with quality midstream partners
Procurement: Comprehensive RFQ(2) processes for certain key services
conducted every 3-6 months
Quality Control: High-performing crews facilitated step-change in completion
efficiency in 2H18
Parsley Real-World Examples
Development Approach: Shift to 2019 “ROR-Optimized” plan in late-2018
required corporate agility and cohesive interdisciplinary collaboration
Integration: Buildout of water infrastructure created a strategic asset
Activity Cadence: Absorbed recent downshift from 16 rigs to 11 rigs
without disruption
Mega-Scale
Preferred Partners
Pricing Power
Operational Continuity
Info Dataset / Implementation
Mid/Downstream Integration Need
Friction Costs
Limited/Volatile
Limited
Small / Rapid
Low-to-Moderate
High
Dynamic
Moderate-to-Strong
Strong
Moderate / Fast
Opportunistic
Moderate-to-Low
Smaller vendor pool
Strong
Strong
Large / Slow
Growing
Low
30
5 rigs or less
Measuring Permian Scale by Rig Count(1)
6-20 rigs 20+ rigs
Corporate Benefits fromFlexibility & Scale
Small-Scale Optimal Scale Mega-Scale
+
+
+
+
+
+/-
+/-
+/-
+/-
+
+
+
-
-
-
+/-
+
-(1) DrillingInfo. Active horizontal drilling rigs in Midland and Delaware Basins as of 8/2/2019 pro forma for announced corporate M&A activity; (2) Request for quotation.
MS Monitor peer results (Midland/Martin)
JM Monitor peer results (Midland/Martin)
LS Initial Parsley operated test (Upton) Increased proppant (Midland/Martin)
UWCA Initial test (Upton)
WCA Test lower proppant loadings Increased proppant (All Counties)
UWCBStacked configuration (Upton/Reagan); 330’ density tests (Reagan)
Stacked configuration (Upton/Reagan) and lower proppant tests
Stagger configuration (Upton/Reagan) and increased proppantLWCB
WCC Initial success (Reagan) Delineation work (Reagan/Glasscock) Defer activity (low Waha prices)
WCD Monitor peer results (Midland/Reagan)
3BS Initial test (Reeves) Monitor peer results
UWCA Initial test (Pecos) Stagger configuration
LWCA Increased proppant (Pecos)
UWCB Initial test (Pecos) Monitor peer results
Achieve scale
Large rig ramp and delineation-heavy development program
~8-16 across
Recapture operational efficiency
Steady development pace across geographically balanced program
Boost capital efficiency by 12-14%+ and accelerate progress to self-funded growth
Reduce activity, increase proppant, high-grade development approach
~8 across ~4-8 across
22
Optimizing the 2019 Plan
“Transformational” 2017 “Simplified” 2018 2019 Action Plan
Agenda
Program Details
Midland Basin
Well Selection
Delaware Basin
Well Selection
Spacing Pattern(Wells/Section/Bench)
“NPV-Focused” “ROR-Focused”
Primary Development Focus Secondary Development Focus (1-2 wells) Future Development Potential
23
Adjusted EBITDAX & Net Leverage Ratio Reconciliations
Note: Certain reclassifications to prior period amounts have been made to conform with current presentation.
Unaudited, in thousands
3Q18 4Q18 1Q19 2Q19Adjusted EBITDAX reconciliation to net income:
Net income (loss) attributable to Parsley Energy, Inc. stockholders $113,309 $53,773 ($24,064) $115,935 Net income (loss) attributable to noncontrolling interests 20,840 11,626 (3,939) 19,059 Depreciation, depletion and amortization 157,352 160,754 173,723 198,563 Exploration and abandonment costs 11,140 142,622 22,994 72 Interest expense, net 32,854 32,880 33,002 33,597 Interest income (1,055) (600) (291) (103)Income tax expense (benefit) 32,454 16,453 (7,790) 32,625
EBITDAX $366,894 $417,508 $193,635 $399,748 Change in TRA liability — 355 — —Stock-based compensation 4,686 4,757 5,322 4,976 Acquisition costs — 165 — —Gain on sale of property (1,383) (16) — —Accretion of asset retirement obligations 361 348 345 353 Restructuring and other termination costs — — — 1,562 Inventory write down 451 — — —Loss (gain) on derivatives 22,514 (93,115) 119,687 (19,561)Net settlements on derivative instruments 9,376 8,600 (8,339) (8,455)Net premiums on options that settled during the period (17,853) (19,115) (9,516) (10,232)
Adjusted EBITDAX $385,046 $319,487 $301,134 $368,391
2Q19Net Leverage Ratio:
Revolving Credit Agreement due 2021 $40,000 6.250% senior unsecured notes due 2024 400,000 5.375% senior unsecured notes due 2025 650,000 5.250% senior unsecured notes due 2025 450,000 5.625% senior unsecured notes due 2027 700,000
Total Debt $2,240,000 Less: Cash and cash equivalents 64,099
Net Debt $2,175,901 LTM Adjusted EBITDAX 1,374,058
Net Debt to LTM Adjusted EBITDAX 1.6x
24
Operating Cash Margin Reconciliation
Unaudited, in thousands
2019 2018
Net income attributable to Parsley Energy, Inc. stockholders $115,935 $119,155
Net income attributable to noncontrolling interests 19,059 21,803
Income tax expense 32,625 33,243
Other revenues (1,200) (1,953)
Depreciation, depletion and amortization 198,563 145,552
Exploration and abandonment costs 72 3,366
Stock-based compensation 4,976 5,363
Acquisition costs — (2)
Accretion of asset retirement obligations 353 359
Other operating expense 2,199 2,477
Interest expense, net 33,597 33,758
Gain on sale of property — (5,166)
Restructuring and other termination costs 1,562 —
(Gain) loss on derivatives (19,561) 9,466
Interest income (103) (1,686)
Other income (715) (234)
Operating cash margin $387,362 $365,501
Operating cash margin per Boe $30.38 $37.25
Average price per Boe, without realized derivatives $39.01 $47.48
Operating cash margin percentage 78% 78%
Three Months Ended June 30,
Note: Certain reclassifications to prior period amounts have been made to conform with current presentation.
25
Free Cash Flow Reconciliation
Free Cash Flow (Outspend)Free cash flow (outspend) is a non-GAAP financial measure and is defined as cash flow from operations before changes in operating assetsand liabilities less accrual-based development capital expenditures. Please refer to the table below for the reconciliation of free cash flow(outspend).
Unaudited, in thousands
Net cash provided by operating activities $615,882
Less: Changes in operating assets and liabilities, net of acquisistions
Accounts receivable (13,417)
Accounts receivable - related parties (798)
Other current assets 7,245
Other noncurrent assets (805)
Accounts payable and accrued expenses 18,465
Revenue and severance taxes payable 4,866
Total discretionary cash flow $600,326
Development of oil and natural gas properties ($737,194)
Additions to oil and natural gas properties - change in capital accruals (41,124)
Total accrual-based development capital expenditures ($778,318)
Free cash flow (outspend) ($177,992)
Six Months Ended June 30, 2019
26
Reserves Disclosure
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 withreasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day ofthe month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonablycertain, regardless of whether deterministic or probabilistic methods are used for the estimation.
In this presentation, proved reserves attributable to Parsley as of 12/31/2018 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on an unweighted first dayof the month average 12-month WTI Phillips 66 posted price, net of differentials, of $61.88/Bbl for oil and $28.05/Bbl for NGLs and a WAHA spot natural gas price, net of differential, of$1.64/MMBtu for natural gas. References to our estimated proved reserves as of 12/31/2018 are derived from our proved reserve report audited by Netherland, Sewell & Associates, Inc. (“NSAI”).
We may use the term “expected ultimate recoveries” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved,probable and possible reserves, and which the SEC's guidelines strictly prohibit Parsley from including in filings with the SEC. Unless otherwise stated in this presentation, such estimates 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, probableand possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. Weinclude these estimates to demonstrate what we believe to be the potential for future drilling and production by the Company. Actual locations drilled and quantities that may be ultimatelyrecovered from our properties will differ substantially. In addition, we have made no commitment to drill all of the drilling locations we identify. Ultimate recoveries will be dependent uponnumerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgetsbased 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 interestleases. Our estimates may change significantly as development of our properties provides additional data and therefore actual quantities that may ultimately be recovered will likely differ fromthese estimates. Our related expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking andoutcome of future drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases.
Unless otherwise noted, Net Present Value (“NPV”) estimates are before taxes and assume the Company generated EUR and decline curve estimates based on Company drilling and completioncost 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 organicreserves replacement ratio is calculated as total reserve additions and revisions (technical and pricing), divided by total production. The ratio calculation excludes acquisitions and divestitures.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 futurereserves.
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 2018 capital expenditures (including Infrastructure and Other) divided by total 2018 proved developed reserves additions and revisions (technical and pricing). Drillbit F&D is calculated as total 2018 capital expenditures (including Infrastructure and Other), divided by total 2018 reserves additions and revisions (technical and pricing). Both calculations exclude acquisitions and divestitures and are subject to limitations, including the uncertainty of future costs to develop the company’s reserves. Oil and gas PD F&D cost is calculated by dividing annual development capital expenditures by year-over-year proved developed producing and proved developed non-producing reserve additions, and includes reclassifications and technical and pricing revisions, but excludes acquisitions and divestitures.
Recycle RatioParsley uses recycle ratio as a measure of its capital efficiency based on its finding and development costs. Recycle ratio is calculated as operating cash margin divided by all costs PD F&D.