East Texas Eagle Ford Acquisition
May 2017
Forward-Looking Statements
This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. Forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,”
“forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “outlook,” “continue” the negative of such terms or other comparable
terminology. All statements, other than historical facts included in this presentation, that address activities, events or developments that WildHorse Resource Development
Corporation (WRD) expects or anticipates will or may occur in the future and such things as WRD’s future capital expenditures (including the amount and nature thereof),
business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of WRD’s business and operations, plans, market conditions,
references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only
as of the date of this presentation. Although WRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are
reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is
expressed, implied or forecast in such statements.
WRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond WRD’s
control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: commodity price
volatility; inflation; lack of availability of drilling and production equipment and services; ability to consummate pending acquisitions; environmental risks; drilling and other
operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to
capital; and the timing of development expenditures. Information concerning these and other factors can be found in WRD’s filings with the Securities and Exchange
Commission (SEC), including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this presentation are qualified by these cautionary
statements and there can be no assurances that the actual results or developments anticipated by WRD will be realized, or even if realized, that they will have the expected
consequences to or effects on WRD, its business or operations. WRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements,
whether as a result of new information, future results or otherwise.
Please see “Cautionary Statements and Additional Disclosures” below for more information.
Information in this presentation is accurate as of March 31, 2017, unless otherwise noted.
1
Acquisition Overview
Asset Overview
Transaction Summary



On May 11, 2017, WRD announced a $625 million acquisition of ~111,000 net acres in Burleson,
Brazos, Robertson, Milam, Washington and Lee counties from Anadarko Petroleum Corporation
(“Anadarko” or “APC”) and affiliates of Kohlberg Kravis Roberts & Co. L.P. (“KKR”)
$625 million acquisition consideration includes:
• $121 million revolving credit facility borrowings
• ~$69 million in common shares issued to KKR at closing, ~6.3 million shares
• $435 million in Series A Perpetual Convertible Preferred Stock issued at closing to The
Carlyle Group, through its U.S. buyout fund Carlyle Partners VI
Target closing date of June 30, 2017 with an effective date of January 1, 2017
Robertson
Milam
Brazos
Burleson
Asset Highlights







~111,000 net acres with an average 8/8th NRI of ~80%
• ~95% held-by-production
• 22.9 MMBoe proved developed producing (PDP) reserves (73% oil and 88% liquids)
• Pro forma Eagle Ford position of 385,000 net acres
Expect to allocate a portion of our 2017 development program to higher working interest wells in
and around the acquired acreage
Single-well IRRs consistent with existing Gen 3 Eagle Ford wells
• Attractive 55% single-well IRR for 91 Boe/ft type curve(1)
949 net locations with 711 of the net locations in the Eagle Ford 91 Boe/ft type curve areas
4Q16 production of ~7.6 MBoe/d (~54% Eagle Ford) from 68 Eagle Ford, 299 Austin Chalk and
19 Buda/Georgetown operated wells
Total WRD 1Q17 status quo production of 17.6 MBoe/d; pro forma total production of 25.2
MBoe/d(2)
Legacy acquired wells were completed with Gen 1 style fracs utilizing, on average, ~1,100 lbs / ft
of proppant
• Average EUR of 44 Boe/ft for existing Eagle Ford wells (less than half of the WRD 91 Boe/ft
type curve)
• Significant future refrac opportunities
1.
2
2.
Lee
Washington
WRD
APC / KKR Acquisition
20
0
Miles
Fayette
Austin
WildHorse Acquisition Geologic Criteria
WRD Eagle Ford
APC / KKR Acquisition
High Oil Cut
✓
✓
Carbonate Rich
✓
✓
Attractive Oil Gravity
✓
✓
High Pore Pressure
✓
✓
See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for
2021 and thereafter for WTI and Henry Hub, respectively.
WRD status quo Q1 2017 reported production; announced acquisition adjustment based on Q4 2016 production.
Compelling Rationale for Transformative Acquisition
Largely undeveloped acreage contiguous to the existing Eagle Ford position
 ~111,000 net acres in the Eagle Ford
Adds Significant Scale
High Quality Eagle
Ford Inventory
Liquidity Enhancing
and Credit Neutral
Midstream
Infrastructure in Place
Additional Upside
1.
2.
3
3.
4.
 Increases total Eagle Ford acres by 40%
 Direct bolt-on helps mitigate planning issues around partially owned units
 Pro forma total WRD daily production of approximately 25.2 MBoe/d (1)
 Single-well IRRs consistent with existing Gen 3 Eagle Ford wells
• 711 net locations in the Eagle Ford 91 Boe/ft type curve area with attractive single-well IRRs of 55%(2)
• Average 8/8ths NRI of ~80%
• Current Gen 3 wells outperforming the Eagle Ford type curve by ~11%
 Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the
acquired acreage
 Solid PDP base with acquired 4Q16 production of ~7.6 MBoe/d (89% liquids)
 Financing structure supports liquidity and ability to fund development plan; expected pro forma liquidity after giving
effect to the acquisition of ~$620mm
 Net debt / Annualized EBITDAX(3) remains approximately 1.9x pro forma for the acquisition
 62% of remaining 2017E pro forma production hedged at attractive prices (4)
 Pipeline infrastructure in place
 Takeaway capacity leads to low differentials
 Competitive advantage on water cost
 Second landing target in the Eagle Ford with potential downspacing opportunities adds significant upside
 Additional upside potential in other horizons: Austin Chalk, Georgetown, Buda, Pecan Gap and Woodbine
 Refrac potential on initial understimulated Eagle Ford wells with an average of 1,100 lbs / ft gel fracs
WRD status quo Q1 2017 reported production; announced acquisition adjustment based on Q4 2016 production.
WRD location count for acquisition based on 500’ spacing and includes only net locations located in the 91 Boe/ft type curve area. See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of
4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively.
See Net Debt and EBITDAX reconciliations on page 23 and 25. WRD status quo Q1 2017 reported EBITDAX; announced acquisition adjustment based on Q4 2016 EBITDAX.
Based on midpoint of updated FY 2017 guidance.
Eagle Ford Acreage Growth and Consolidation
WildHorse continues to execute on proven strategy of organic leasing and targeted acquisitions to grow
our high quality Eagle Ford acreage position to 385,000 net acres
Washington – January 2015
Formation
Washington
1st CWEI Acquisition – June 2015
Previous Position
1st CWEI Acquisition
Brazos
2nd CWEI Acquisition – Dec 2015
Previous Position
Organic Leasing / Swaps
Brazos
Burleson
20
0
Miles
1.
4
3rd CWEI Acquisition – Oct 2016
Previous Position
Brazos
3rd CWEI
Acq.
Includes three acquisitions in Lee County that occurred over ~12 months.
APC / KKR – May 2017
Previous Position
APC / KKR Acq.
Brazos
Burleson
Washington
Brazos
Burleson
Lee
Lee
Washington
Washington
Washington
Burleson
Lee
Lee
Washington
Organic Leasing / Acreage Swaps
Brazos
Burleson
Lee
Washington
Previous Position
Lee
Brazos
Burleson
Lee
Lee
Previous Position
2nd CWEI Acquisition
Previous Position
Comstock Acquisition
Brazos
Burleson
Burleson
Lee – September 2015(1)
Comstock Acquisition – July 2015
Lee
Washington
Washington
Announced Transaction Similar to Clayton Williams
Combined acquisition price of ~$1.025 billion for 269,000 net acres or ~$2,100/net acre (1)
Acquisition Comparison
CWEI Acquisition
Announced Acquisition
$400 million
$625 million
~158,000 Net Acres
~111,000 Net Acres
~3.9 MBoe/d
~7.6 MBoe/d
637
711
80% Oil / 87% Liquids
72% Oil / 89% Liquids
✓
✓
✓
✓
✓
✓
Purchase Price
Large Adjacent Acreage Position
Production(2)
Net Locations in 91 Boe/ft Type
Curve Inventory(3)
High Oil / Liquids Cut(2)
Comparable Geologic Properties &
Economics to WRD Eagle Ford
Developed Midstream and Water
Infrastructure
Expands 91 Boe/ft Type Curve
Inventory
5
1.
2.
3.
Assuming $40,000 per flowing barrel for acquired PDP production.
Based on CWEI Q3 2016 production and announced acquisition Q4 2016 production.
WRD location counts based on 500’ spacing and include only net locations located in the 91 Boe/ft type curve area.
Pro Forma WRD Will Operate the Second Largest Eagle Ford Position
Net Acreage Positions(1)
Operator Acreage Positions(1)
Eagle Ford Shale
Oil
Wet Gas/Condensate
Dry Gas
(000s Acres)
EOG Resources
(2)
WildHorse
590
274
Acq.
Sanchez Energy
335
Chesapeake
260
BHP Billiton
252
ConocoPhillips
213
BP
190
SM Energy
NM
OK
TX
80
0
Miles
1.
2.
6
Net acreage positions per Company Investor Presentations, Company Filings and published reports as of 4/30/2017.
WildHorse gives effect to announced acquisition.
168
Murphy Oil
147
Marathon
145
AR
LA
Carrizo
102
385
WRD’s Attractive Eagle Ford Acquisition Metrics Bolster Full Cycle Returns
WRD has agreed to acquire Eagle Ford acreage at attractive economics per net location on a PDP-adjusted basis
 Over its last two major Eagle Ford acquisitions, WRD has averaged ~$420,000 / net location for 1,348 net locations
 Since 1/1/2016, acquisitions in the Permian Basin have averaged ~$1.8 million / net location and transactions in the SCOOP / STACK have averaged
~$1.0 million / net location
PDP Adjusted Purchase
Price(1) / Net Locations
PDP Adjusted Purchase
Price(1) / Total Acres
($ 000's / location)
Purchase Price / Total Acres
($ / acre)
$2,000
($ / acre)
$30,000
$40,000
~$27,000
~$1,750
$25,000
$1,600
~$31,250
$30,000
$20,000
$1,200
$944
$15,000
$650
$20,000
$10,000
~$7,000
7
Permian Basin
SCOOP / STACK
Hawkwood / Halcon
Venado / Exco
WRD EF Acquisitions
Permian Basin
SCOOP / STACK
Venado / Exco
Hawkwood / Halcon
$5,899
$6,211
$3,810
$0
WRD EF Acquisitions
$0
$3,230
$0
Note: WRD location counts for APC / KKR and CWEI acquisitions based on 500’ spacing and include only net locations located in the 91 Boe/ft type curve area. Permian and SCOOP / STACK represent average of transactions from 1/1/2016 to
3/31/2017 based on Company Investor Presentations, Company Filings and published reports.
1.
Purchase Price adjusted for production at $40,000 Boe/d.
Permian Basin
$2,103
$2,674
SCOOP / STACK
$5,000
Hawkwood / Halcon
$400
~$9,500
$10,000
Venado / Exco
$420
WRD EF Acquisitions
$800
~$1,000
Eagle Ford Growth: Significant, High-Quality Scale
Eagle Ford Net Acres
4Q16 Eagle Ford Daily Production
Eagle Ford Net Locations
(Locations)
(Net Acres in 000s)
(MBoe/d)
3,000
450
20
18.6
400
2,651
385
2,500
16
350
300
2,000
274
1,702
12
250
11.0
1,500
200
8
150
1,000
100
4
500
50
0
8
0
0
WRD EF
Status Quo
WRD EF
Pro Forma
WRD EF
Status Quo
WRD EF
Pro Forma
WRD EF
Status Quo
WRD EF
Pro Forma
Recent Well Results Outperform and Delineate Extensive Acreage Position
 WRD Gen 3 wells continue to outperform 91 Boe/ft type curve across the acreage
position
• >80% of Gen 3 wells drilled to date are performing above 91 Boe / ft type
curve EUR
 Current Eagle Ford producing wells exist across entire ~800 square mile area
Gen 3 Completions Outperforming Type Curve (6 Mo Cum)(2)
Jackson #1H
EUR: 110+ Boe/Ft
IP30= 958 BOE/D (85% oil)
6,297’ LL (3/27/2017)
Altimore #1H
EUR: 120+ Boe/Ft
IP30 = 1,048 BOE/D (84% oil)
6,435’ LL (3/31/2017)
120,000
Cumulative Production (Boe)
Horizontal Well Activity(1)
Candace #1H
EUR: 138 Boe/Ft
IP30 = 1,081 BOE/D (88% oil)
7,481’ LL (9/2/16)
100,000
80,000
Paul 134 Unit #2H
EUR: 130+ Boe/Ft
IP30 = 1,035 BOE/D (93% oil)
5,363’ LL (3/8/17)
60,000
WildHorse
40,000
Cooper B #1H
EUR: 107 Boe/Ft
IP30 = 576 BOE/D (85% oil)
4,780’ LL (12/12/16)
20,000
20
0
3rd Party EF HZ Well
Mach A #2H
EUR: 111 Boe/Ft
IP30 = 607 BOE/D (64% oil)
6,672’ LL (2/22/17)
Miles
WRD Acreage with Locations
Additional WRD Acreage(3)
Belmont Stakes #1H
EUR: 135 Boe/Ft
IP30 = 740 BOE/D (65% oil)
5,831’ LL (10/1/16)
Kentucky Derby #1H
EUR: 100 Boe/Ft
IP30 = 594 BOE/D (55% oil)
5,126’ LL (10/1/16)
IRR Sensitivity at Consensus Price Deck(4)
0
0
30
60
90
Days
120
Gen 3 Avg
Avg Boe
Boe Cum
Cum (23 wells)
Burleson
Type Curve
91
Boe/ft Main
Type Curve
CandaceGen
#1H
Recent
3 Well Results
9
1.
2.
3.
4.
150
180
EUR (Boe / Ft)
91
100
110
120
130
140
55%
68%
84%
100%
121%
145%
Data for WildHorse based on actual results reported by WildHorse management. The initial production rates represent the peak average of the IP rates for the applicable consecutive days of production; IP rates are not normalized for lateral length. Dates are first production.
The first day of the peak IP30 rate is considered day 1 of cumulative production. Data is normalized for 6,500’ laterals, downtime, and irregular production.
Represents ~130,000 net acres with no locations assigned – under evaluation.
See slide 14 for assumptions embedded in Eagle Ford IRR calculation. IRR based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and
Henry Hub respectively.
Gen 3 Design Outperforms Legacy Eagle Ford Development Wells
Robertson
Well Name
Candace 1H
Operator Frac Gen Boe/Ft
WRD
3
138
Galaxy 1H
APC
1
38
Bronco 3 Well Pad
APC
1
33
Whitney 103 2 Well Pad
CWEI
1
59
Peters 112 2 Well Pad
CWEI
<1
44
Abbot 100 2 Well Pad
CWEI
<1
45
Milam
Brazos
Well Name
War Wagon 2 Well Pad
Operator Frac Gen Boe/Ft
APC
1
43
Misfits 2 Well Pad
APC
1
36
Zemanek 2 Well Pad
APC
1
71
Foxfire 2 Well Pad
APC
1
42
Capps 2 Well Pad
APC
1
78
Well Name
Altimore #1H
Operator Frac Gen Boe/Ft
WRD
3
120+
Jackson #1H
WRD
Well Name
Snap B 1H
Operator Frac Gen Boe/Ft
WRD
3
137
3
110+
Well Name
Paul 134 #2H
Operator Frac Gen Boe/Ft
WRD
3
130+
Spitfire 2 Well Pad
APC
<1
61
Snap F 1H
WRD
3
98
Victorick 2 Well Pad
APC
1
96
Elm 2 Well Pad
APC
<1
46
Yucca 2 Well Pad
APC
<1
62
Capstone 2 Well Pad
APC
1
94
Boxwood 1H
APC
1
62
Porter E #1H
CWEI
<1
29
Well Name
Belmont Stakes 1H
Operator Frac Gen Boe/Ft
WRD
3
135
Kentucky Derby 1H
WRD
3
100
Sassafras 2 Well Pad
APC
1
39
Well Name
Cooper B 1H
Operator Frac Gen Boe/Ft
WRD
3
107
Mach A 2H
WRD
3
Burleson
111
Lee
Washington
WRD Wells
APC Wells
CWEI Wells
0
20
Miles
Note: Gray shading denotes WildHorse completions. Less than Gen 1 completions represent proppant loads less than 1,000 lbs/ft; Gen 1 completions represent proppant loads between 1,000 and 1,800 lbs/ft; Gen 2 completions represent proppant
loads between 1,800 and 3,000 lbs/ft; Gen 3 completions represent loads greater than 3,000 lbs/ft.
10
WildHorse Acreage Positioned in the Highly Productive,
Liquids-Rich Eagle Ford

Geology matters:
•
Gas to oil ratio
0
•
•
•

Gross Eagle Ford thickness ranges
from over 100’ to greater than
400’ across the acreage position

Thickness allows greater potential
for stacked / staggered
development opportunities in both
the Eagle Ford and the Chalk

Milam
Grimes
Grimes
Milam
-6,000'
-7,000'
Brazos
300'
250'
Bastrop
Fayette
WRD Acreage
AustinAPC / KKR Acquisition
-13,000'
Waller
-14,000'
Deep
Fayette
Oil Gravity
150'
100'
50'
Austin
WRD Acreage
APC / KKR Acquisition
Thin
Gas / Oil Ratio
API
20
Miles
60.0
Milam
200'
Washington
-12,000'
0
400'
Lee
-11,000'
Waller
500'
350'
-10,000'
Washington
Thick
450'
Burleson
-8,000'
Lee
0
20
Grimes
Burleson
Mcf / STB
Miles
10,000
Milam
57.5
Brazos
Brazos
55.0
52.5
9,000
Grimes
47.5
6,000
Lee
5,000
4,000
45.0
Lee
Washington
WRD Acreage
APC / KKR Acquisition
42.5
40.0
37.5
35.0
8,000
7,000
Burleson
50.0
Fayette
11
Shallow
-9,000'
Clay content increases in the
Northeast portion of the play in
Brazos and Madison counties
Rich carbonate content and lower
clay content allow more effective
hydraulic fracturing
Brazos
Burleson
Pore pressure – geopressure
of ~0.75 Psi / Ft
20
Miles
Oil gravity
The Eagle Ford is a Cretaceous
sediment where the formation’s
carbonate content can exceed 70%
in WildHorse’s position
0
20
Miles
Clay content


Gross Thickness Isopach Map
Top of Eagle Ford Structural Map
Washington
Bastrop
Fayette
WRD Acreage
APC / KKR Acquisition
3,000
2,000
1,000
250
Consistent Geology Across WRD’s Eagle Ford Position
Burleson County
Brazos County
A
Austin
Chalk
A’
Target
Zone
Eagle Ford Shale
Paul 134 #2H
Offset Well
Buda
A’
12
A
Acquisition Further Extends Deep Inventory of Economic Locations
Net Horizontal Locations by Area
Inventory Breakevens (10% Pre-tax IRR)
Net Locations(1)
Net Locations
3,299 Net
Locations
Multiple decades of drilling
inventory across Eagle Ford
and North Louisiana based
on net locations(1)
3,500
3,000
655
155
648
493
1,996
2,000
949
417
711
1,500
1,000
North Louisiana Locations
Other
13
646
648
2,000
219
763
763
763
1,500
711
1,573
1,587
1,587
$45.00 / $2.50
$55.00 / $3.00
$65.00 / $3.50
1,199
0
RCT
Other
Total
Locations
Eagle Ford
North Louisiana
Additional upside locations in:
 ~130,000 Eagle Ford net acres with no locations assigned – under evaluation
 Austin Chalk in Burleson County; Buda, Woodbine, Georgetown and Pecan Gap
across much of our Eagle Ford acreage
 Northern Louisiana – Additional Cotton Valley intervals
1.
591
2,129
500
Existing Eagle Ford Locations
Acquisition Locations
Eagle Ford
EUR (91 Boe/ft)
2,998
1,702
1,285
0
2,996
1,000
1,996
500
2,927
3,000
2,500
238
2,500
3,500
$35.00 / $2.00
Existing Eagle Ford
Acquisition
North Louisiana
As of May 11, 2017, we identified 3,299 net horizontal drilling locations, which includes 949 locations associated with our pending acquisition. The locations were specifically identified by management as an estimation of our multi-year drilling activities based on evaluation
of applicable geologic and engineering data. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of our horizontal drilling results and those of other operators across our acreage, combined with our interpretation of available
geologic and engineering data. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Of our 3,299 estimated drilling locations, 201, 342 and 1,156 are
associated with proved, probable and possible reserves as of December 31, 2016. Accordingly, 1,599 of these locations do not have any reserves assigned to them which includes 949 locations associated with the pending acquisition. There are no assurances that these
locations will perform like we expect. All of our assumptions with respect to our drilling locations, including estimated ultimate recoveries, expected costs to drill and complete, internal rates of return and economic break-even prices are speculative in nature and may prove to
be inaccurate.
~2,000 Net Locations with Highly Economic 91 Boe/ft Type Curve
Eagle Ford Single Well Summary
14
1.
2.
3.
555
497
90%
348
594
497
219
60
6%
84%
10%
94%
0.70
6,500
63%
$0.90
621
434
741
114
78%
1.40
6%
1,996
91
$5.6
$862
$5.9
55%
Boe/d
1,000
100
10
1
3
5
7
9
11
13
14
Month
91 Boe/ft Type Curve
16
18
20
22
24
Gen 3 Average Boe
IRR Sensitivity(3)
EUR / 1,000 Ft
(MBoe)
EUR Improvement
Type Well Assumptions
Wellhead EUR (MBoe)
Oil EUR (Mbbl)
% Oil
Gas EUR (MMcf)
Sales EUR (MBoe)
Oil EUR (Mbbl)
Gas EUR(MMcf)
NGL EUR (Mbbl)
% Gas
% Oil
% NGL
% Liquids
GOR (Mcf/bbl)
Lateral Length (ft)
Shrinkage
Variable Water Cost ($/Water Bbl)
Type Curve
30-day Oil IP (Bbl/d)
30-day Gas IP (Mcf/d)
30-day IP (Boe/d, 3-Stream)
30-day IP (Boe/d) per 1,000'
Initial Decline (%)
B Factor
Terminal Decline (%)
Summary(1)
Net Drilling Locations (2)
EUR / 1,000 Foot (MBoe)
D&C ($MM)
D&C / Foot
NPV10 ($MM)
IRR (%)
91 Boe/ft Type Curve (with all 23 Gen 3 well results)
Oil Price
%
$45.00
$50.00
$55.00
$60.00
$65.00
91
0%
27%
37%
47%
59%
71%
100
10%
35%
46%
59%
72%
89%
110
21%
45%
59%
74%
93%
113%
120
32%
55%
72%
92%
114%
140%
130
43%
67%
88%
111%
140%
175%
140
54%
80%
105%
134%
172%
212%
Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019, $66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively.
See slide 13 for further information regarding our drilling locations.
IRR sensitivities assume $3.00 Henry Hub for the life of the well.
Acquisition Structure and Financing Overview
Key Transaction Details
Pro Forma Capitalization
 $625 million acquisition consideration:
• $121 million revolving credit facility borrowings
• $69 million in common shares issued to KKR (~6.3 million
shares)
• $435 million in Series A Perpetual Convertible Preferred
Stock issued at closing to The Carlyle Group, through its
U.S. buyout fund Carlyle Partners VI
 Expected $200 million increase in the revolving credit facility’s
borrowing base to occur with closing
Sources and Uses
15
1.
2.
3.
4.
($ in millions)
Sources
RBL Borrowing
Common Shares to KKR
Preferred Equity
$121
69
435
Total Sources
$625
Uses
Purchase Price
$625
Total Uses
$625
3/31/2017
Status Quo
Acquisition
Adj.
Pro Forma
Acq.
$93
-
$93
WRD Revolving Credit Facility
6.875% Senior Notes
Total Debt
350
$350
$121
$121
$121
350
$471
Series A Perpetual Convertible Preferred
Equity Issued to KKR
Stockholders Equity
1,061
$435
69
69
$435
69
1,130
Financial & Operating Statistics
Annualized EBITDAX (1)
Interest Expense (2)
(3)
Latest Daily Production (Mboe/d)
$138
24
17.6
$63
4
7.6
$202
28
25.2
Liquidity
Borrowing Base
Cash
Revolver Borrowings
Letters of Credit
Total Current Liquidity
$450
$93
(1)
$543
$200
(121)
$79
$650
93
(121)
(1)
$622
($ in millions)
Cash
Credit Metrics (4)
Net Debt / Latest Daily Production ($ / Boe/d)
Net Debt / Annualized EBITDAX (1)
Interest Coverage (2)
WRD status quo Q1 2017 reported EBITDAX; announced acquisition adjustment based on Q4 2016 EBITDAX.
Interest Coverage calculated as EBITDAX / Interest; assumes status quo interest expense based on 6.875% notes and pro forma adjustment assumes 3.52% rate on revolver borrowings.
WRD status quo Q1 2017 reported production; announced acquisition adjustment based on Q4 2016 production.
Credit metrics assume 100% equity treatment for the Series A Perpetual Convertible Preferred.
$14,583
1.9x
5.7x
$14,998
1.9x
7.1x
WRD Perpetual Convertible Preferred Equity Summary
Issuer

WildHorse Resource Development Corporation (NYSE: WRD)
Purchaser

The Carlyle Group, through its U.S. buyout fund Carlyle Partners VI
Size

$435 million
Date of Original Issue

Closing date in conjunction with the acquisition closing; target of June 30, 2017
Security

Series A Perpetual Convertible Preferred Stock
Maturity

Perpetual

Conversion Price of $13.90 per share based on a 20% premium to WRD’s 30-day VWAP per share; WRD’s 30-day VWAP represents $11.58 per
share as of May 10, 2017

31,294,964 fully converted shares based on a Conversion Price of $13.90 per share

6.0% annually payable quarterly in arrears in-kind by addition to the liquidation preference, cash or a combination thereof at WRD’s sole election.
WRD intends to PIK the dividend
After 2.5 years if the stock price is equal to or greater than 130% of the Conversion Price, or $18.07, for 25 consecutive trading days dividends
terminate permanently
Conversion Premium / Price
Total Conversion Shares
Dividend
16

Conversion Rights


Issuer: After four years, if the stock price is equal to or greater than 140% of the Conversion Price, or $19.46, for 20 consecutive trading days
Holder: At Conversion Price of $13.90 after one year
Financial Covenants

No financial covenants
Ranking / Capital Structure

Mezzanine equity; junior to all indebtedness and senior to common stock
Voting Rights / Governance

Will vote on an as converted basis; The Carlyle Group to elect two directors to the WRD Board
Updated FY 2017 Guidance; Pro Forma for Acquisition
 Expect to allocate a portion of our 2017 development program to higher working interest wells in and around the
acquired acreage
 Updated Guidance reflects ~1 MBoe/d in outperformance and ~3 MBoe/d for acquisition (expected production for
July – Dec 2017)
2017 Guidance
Prior Guidance
Low
High
Net Average Daily Production (MBoe/d)
Oil (% of Production)
Natural Gas (% of Production)
NGLs (% of Production)
23
52%
35%
8%
Average Costs (per Boe)
Lease Operating Expense
Gathering, Processing, and Transportation
Taxes Other than Income
Cash General and Administrative (1)
$2.75
$0.95
$2.00
$2.75
- 27
- 56%
- 38%
- 10%
-
$3.25
$1.15
$2.25
$3.25
Updated Guidance
Low
High
27
57%
29%
9%
$3.25
$0.95
$2.00
$2.50
- 31
- 61%
- 33%
- 11%
-
$3.75
$1.15
$2.25
$3.00
(2)
17
Commodity Price Realizations (Unhedged)
Crude Oil Realized Price (% of WTI NYMEX)
Natural Gas Realized Price (% of NYMEX to Henry Hub)
NGL Realized Price (% of WTI NYMEX)
95% - 100%
95% - 100%
22% - 27%
95% - 100%
95% - 100%
27% - 32%
Drilling Program
Wells Spud (Gross)
Wells Completed (Gross)
D&C Capital Expenditure ($MM)
90
80
$450
100
85
$550
- 110
- 100
- $600
- 120
- 105
- $675
Note: Guidance as of May 11, 2017. Updated guidance includes announced acquisition results beginning July 1, 2017.
1.
Excludes non-cash compensation charges associated with grants under our LTIP and incentive units issued to certain of our officers and employees. WRD does not guide to anticipated average non-cash general and administrative costs.
Please see cautionary language under “Cautionary Statements and Additional Disclosures” for additional disclosures because such compensation charges are based in part on the price of our common stock and are too speculative to predict.
2.
Based on strip pricing as of May 11, 2017.
WildHorse Commodity Hedging Overview – Pro Forma for Acquisition
 WildHorse’s commodity risk management policy provides for hedging estimated production from total proved reserves
 Proactive policy reduces WildHorse’s exposure to movements in commodity prices and provides stability to cash flows
 All trading counterparties have investment grade credit ratings at both S&P and Moody’s
 Current hedges include primarily costless, fixed price swaps and collars, as well as deferred premium puts
Hedge Summary as of May 11, 2017
Remaining
2017(1)
Crude Oil Hedge Contracts:
Total crude oil volumes hedged (Bbl)
Volumes hedged (Bbl/d)
(2)
Total weighted-average price ($/Bbl)
(3)
% of 2017 Expected Production
Natural Gas Hedge Contracts
Total natural gas volumes hedged (MMBtu)
Volumes hedged (MMBtu/d)
(2)
Total weighted-average price ($/MMBtu)
(3)
% of 2017 Expected Production
Total Hedge Contracts
Total hedged production (MBoe)
Volumes hedged (Boe/d)
(2)
Total weighted-average price ($/Boe)
(3)
% of 2017 Expected Production
18
1.
2.
3.
Remaining 2017 represents April 1 through December 31, 2017.
Using the midpoint for collars and floors of puts.
FY17 represents mid-point of updated guidance.
2018
2019
3,277,054
11,917
$52.71
60%
4,450,409
12,193
$53.61
-
2,874,098
7,874
$54.19
-
13,581,895
49,389
$3.09
86%
11,565,800
31,687
$3.03
-
9,877,900
27,063
$2.81
-
5,540,703
20,148
$38.74
62%
6,378,042
17,474
$42.90
-
4,520,415
12,385
$40.60
-
Key Acquisition Benefits for WildHorse
P
Acquisition Increases WRD’s Highly Contiguous Eagle Ford Acreage Position by ~40%
P
Positions WRD as 2nd Largest Eagle Ford Operator with ~385,000 Pro Forma Net Acres
P
Significant Development Potential and Running Room with 2,651 Pro Forma Eagle Ford Net Locations
P
Attractive Geology with High Oil Cut, Carbonate Rich, Attractive Oil Gravity and High Pore Pressure
P
Financing Structure Protects Balance Sheet, Includes Significant Hedging and Maintains Target Leverage at <2.0x
19
WRD Has Built a Premier Platform for Growth
Premier Acreage Positions in the East Texas Eagle Ford and North Louisiana Over-Pressured Cotton Valley
Total Company
Net Acres (1)
Proved Reserves (MMBoe)(2)
% Liquids
% Oil
Q1 2017 PF Production (Mboe/d)
% Liquids
Drilling Locations:
Gross
Net
~489,000
175.4
68%
59%
25.2
68%
OK
AR
5,829
3,299
In and around the prolific
Terryville Complex
TX
Eagle Ford
Net Acres (1)
Proved Reserves (MMBoe)(2)
% Liquids
% Oil
Q1 2017 PF Production (Mboe/d)
% Liquids
Drilling Locations:
Gross
Net
Single-well IRR (3)
20
MS
Second largest Eagle Ford
position in the industry
Total Company
~385,000
127.6
92%
81%
19.1
88%
4,416
2,651
~55%
LA
North Louisiana
Net Acres (1)
Proved Reserves (Bcfe)(2)
% Gas
Q1 2017 Production (Mmcfe/d)
% Gas
Drilling Locations:
Gross
Net
Single-well IRR (3)
~104,000
286.8
98%
36.3
95%
1,413
648
~69%
Note: Q1 2017 pro forma daily production based on WRD Q1 2017 production plus Q4 2016 production from announced acquisition; drilling locations pro forma for announced acquisition.
1.
Pro forma acreage as of March 1, 2017; Includes pending acquisition of 111,044 net acres; Includes acreage that WildHorse has the right to lease within the Terryville Complex.
2.
Reserve data as of December 31, 2016; includes 22.9 MMBoe in PDP reserves from announced acquisition (audited proved reserves not currently available). 3P Reserve Report audited by Cawley, Gillespie & Associates (“CGA”).
3.
See slide 14 for assumptions embedded in WildHorse IRR calculations. Eagle Ford IRR based on Burleson Main type curve. IRRs based on Consensus Pricing as of 4/26/2017: $54.00 / $3.15 for 2017, $60.00 / $3.11 for 2018, $61.00 / $3.09 for 2019,
$66.50 / $3.25 for 2020, $70.00 / $3.45 for 2021 and thereafter for WTI and Henry Hub, respectively.
Appendix
21
WRD Ownership Chart – Pro Forma Acquisition Closing
The Carlyle Group
NGP and
Management(1)
55.4%(2)
23.8%(2)
Company Shares Breakout
Total Common Shares Outstanding
Shares Issued at IPO
Current Float
Market Capitalization ($MM)
(3)
Status Quo
93,987,541
Pro Forma
100,248,440
29,797,100
29,797,100
19,797,100
26,057,999
$1,066
$1,572
Fully Diluted Equity Ownership
Status Quo
Series A Perpetual Convertible Preferred (Carlyle)
KKR
22
0.0%
Pro Forma
4.8%(2)
WildHorse Resource
Development Corporation
NYSE: WRD
100%
Operating Subsidiaries
23.8%
6.2%
4.8%
NGP + Management
72.7%
55.4%
Public
21.1%
16.1%
1.
2.
3.
KKR
$435MM Series A Perpetual
Convertible Preferred Stock
NGP and Management includes WHR Holdings, LLC; Esquisto Holdings, LLC; WHE AcqCo Holdings, LLC; NGP XI US Holdings, LP and Management.
Fully diluted equity ownership percentages. Pro Forma for announced acquisition and preferred issuance at closing.
As of May 10, 2017; Status Quo excludes convertible preferred shares and Pro Forma includes $435mm Series A Perpetual Convertible Preferred Stock.
Public Stockholders
16.1%(2)
Reconciliation of Adjusted EBITDAX
This presentation and accompanying schedules include the non-GAAP financial measure Adjusted EBITDAX. The accompanying schedule provides a reconciliation of the non-GAAP financial
measure to its most directly comparable financial measure calculated and presented in accordance with GAAP. WRD's non-GAAP financial measures should not be considered as alternatives to
GAAP measures such as Net Income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance
with GAAP. WRD's non-GAAP financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as
WRD does.
Adjusted EBITDAX is a non-GAAP financial measure. We evaluate performance based on Adjusted EBITDAX. Adjusted EBITDAX is defined as net income (loss), plus interest expense;
debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on
commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for
environmental remediation; transaction related costs; IPO related expenses; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and
cash settlements paid; gains on sale of assets and other non-routine items.
The following table presents WRD’s first quarters of 2017 and 2016 EBITDAX to the most comparable measure calculated in accordance with GAAP:
For the Three Months
Ended March 31,
2017
2016
(Amounts in $000s)
Net Income (loss)
Add (Deduct):
Interest expense, net
Income tax (benefit) expense
Depreciation, depletion an amortization
Exploration expense
(Gain) loss on derivative instruments
Cash settlements received / (paid) on commodity derivatives
Stock-based compensation
Acquisition related costs
Debt extinguishment costs
Initial public offering costs
Non-cash liability amortization
Adjusted EBITDAX
23
$
20,252
$
5,571
11,700
26,443
1,615
(31,291)
(983)
495
599
(11)
182
34,572
$
(14,216)
$
1,972
139
22,063
7,443
(3,246)
3,373
358
(183)
17,703
Cautionary Statements and Additional Disclosures
This presentation has been prepared by WildHorse and includes market data and other statistical information from sources believed by WildHorse to be reliable, including
independent industry publications, government publications or other published independent sources. Some data is also based on WildHorse’s good faith estimates, which are
derived from its review of internal sources as well as the independent sources described herein. Although WildHorse believes these sources are reliable, it has not independently
verified the information and cannot guarantee its accuracy and completeness.
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). WildHorse has
provided estimates for proved, probable and possible reserves within this presentation in accordance with SEC guidelines and definitions. The estimates for proved, probable
and possible reserves as of December 31, 2016 have been prepared by WildHorse’s internal reserve engineers and audited by Cawley, Gillespie & Associates, Inc. (“CGA”),
WildHorse’s independent reserve engineers.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
Actual quantities that may be ultimately recovered from WildHorse’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate
recovery include the scope of WildHorse’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production
costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling
results, including geological and mechanical factors affecting recovery rates.
“EUR” or “Estimated Ultimate Recovery,” when referring to a currently producing well, refers to the sum of total gross remaining proved reserves attributable to each location
in WildHorse’s reserve report and cumulative sales from such location. EUR is shown on a combined basis for oil/condensates, gas and NGLs after the effects of processing.
These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineers Petroleum Resource Management System or the
SEC’s rules.
Management Locations
WRD has disclosed net horizontal drilling locations in this press release in the proved, probable, and possible categories as audited by CG&A as well as 1,599 drilling locations
that have been identified by WRD’s management including 949 locations associated with the pending acquisition. WRD identified those additional locations using the same
methodology as those locations to which probable and possible reserves are attributed—by using existing geologic and engineering data from vertical production and seismic
data. Of those 3,299 net horizontal drilling locations, 1,700 lie within the geographic areas to which proved, probable and possible reserves are attributed. The remaining 1,599
management identified net horizontal drilling locations are within geographic areas to which proved, probable or possible reserves are not attributed, but nonetheless are
locations that WRD has specifically identified based on its evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities in the
surrounding area. The locations have been identified by WRD’s management based on its evaluation of applicable geologic and engineering data from historical drilling
activities in the surrounding area. The locations on which WRD actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal
restrictions, oil and natural gas prices, costs, actual drilling results and other factors, and may differ from the locations currently identified.
24
Cautionary Statements and Additional Disclosures (Cont’d)
Cash General and Administrative Expenses per Boe
WRD’s presentation of cash general and administrative (“G&A”) expenses per Boe is a non-GAAP measure. WRD defines cash G&A per Boe as total G&A determined in
accordance with accounting principles generally accepted in the United States of America (“GAAP”) less non-cash equity compensation expenses, expressed on a per-Boe
basis. WRD reports and provides guidance on cash G&A per Boe because it believes this measure is commonly used by management, analysts and investors as an indicator of
cost management and operating efficiency on a comparable basis from period to period. In addition, management believes cash G&A per Boe is used by analysts and others in
valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based
compensation programs which can vary substantially from company to company. Cash G&A per Boe should not be considered as an alternative to, or more meaningful than,
total G&A per Boe as determined in accordance with GAAP and may not be comparable to other similarly titled measures of other companies.
Calculation of Net Debt
Net Debt is a supplemental non-GAAP financial measure that is used by external users of WRD’s financial statements. We define Net Debt as total debt minus cash and cash
equivalents. We believe Net Debt is useful to investors because it provides readers with a more meaningful measure of our outstanding indebtedness. However, this measure is
provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with
GAAP.
25