2. Forward-Looking & Other Cautionary Statements
1
This presentation contains forward-looking statements. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Jones Energy,
Inc. (the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “may,” “estimates,” “will,” “anticipate,” “plan,” “intend,”
“foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-
looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and
operating results of the Company, including as to the Company’s drilling program, drilling locations, production, hedging activities, ability to fund the 2014 capital budget with operating cash flow and credit
facility, capital expenditure levels. Internal rates of return (“IRR”), and other guidance included in this presentation. You should not place undue reliance on these forward-looking statements. These forward-
looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not
possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statements we may make. Although we believe that our plans, expectations and estimates reflected in or suggested by the forward-looking statements we
make in this prospectus are reasonable, we can give no assurance that these plans, expectations or estimates will be achieved or occur, and actual results could differ materially and adversely from those
anticipated or implied in the forward-looking statements. We disclose important factors that could cause our actual results to differ materially from our expectations. These include the factors discussed or
referenced in the “Risk Factors” section of the Company’s 10-K dated 3/14/2014, risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and
demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, impact of compliance with legislation and regulations,
successful results from our identified drilling locations, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results
to differ materially from those projected.
Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of
new information, future events or otherwise, except as required by applicable law.
The Securities and Exchange Commission (“SEC”) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable 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 of the 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 reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible
reserves that meet SEC definitions for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings.
We use the term “EURs” per well in this presentation to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These are based on
the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities do not
constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules. “EUR,” or Estimated Ultimate Recovery, refers to our management’s
internal estimates based on per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. Our management estimated these EURs
based on publicly available information relating to the operations of producers who are conducting operating in these areas.
Factors affecting ultimate recovery include our ability to acquire the acreage we are targeting and the scope of our ongoing drilling program, which will be directly affected by 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. Estimates of per well EUR and drilling locations may change significantly as the Company pursues acquisitions. In addition, 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 and outcome of future drilling activity, which may
be affected by significant commodity price declines or drilling cost increases.
“Drilling locations” represent the number of locations that we currently estimate could potentially be drilled in a particular area. In order to identify drilling locations, we apply a geologic screening criterion based
on presence of a minimum threshold of gross pay sand thickness in a section and then consider the number of sections and the appropriate well density to develop the applicable field. In making these
assessments, we include properties in which we hold operated and non-operated interests, as well as redevelopment opportunities. Once we have identified acreage that is prospective for the targeted
formations, well placement is determined primarily by the regulatory spacing rules prescribed by the governing body in each of our operating areas. We have not completed acreage acquisitions in targeted
areas. Actual acreage acquired, locations drilled and quantities that may be ultimately recovered from the Company’s interests will differ substantially. There is no commitment by the Company to drill all of the
identified drilling locations.
This presentation also includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including Adjusted EBITDAX. Adjusted EBITDAX is a supplemental non-
GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.
We define Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period
settlements of matured derivative contracts and other items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. Management
believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers
without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to
company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX has limitations as an
analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from
Adjusted EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historical costs of
depreciable assets. Our presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX
may not be comparable to other similarly titled measures of other companies.
3. Key JONE Stats
2
IPO Date: July 29, 2013
Ticker: JONE
Exchange: NYSE
IPO Shares: 12,500,000
Total Outstanding Shares: 49,362,913 (12,526,580 Class A, 36,836,333 Class B)
Share Price as of April 3, 2014: $15.74
Market Capitalization: ~$775 million
Enterprise Value: ~$1,400 million
Liquidity Post-Debt Offering: ~$400 million
89 MMBoe (50% PDP / 56% Liquids)
63%
29%
8%
Woodford OtherCleveland
20.4 MBoe/d (53% Liquids)
65%
20%
15%
Woodford OtherCleveland
Proved Reserves Average Daily Production
Note: Proved reserves as of 12/31/13. Daily production pro forma for Sabine acquisition.
4. 3
Company Summary
Anadarko Basin
Key Formation: Cleveland and Tonkawa
Drilling Locations: 1,731
Cleveland Daily Production: 13.2 Mboe/d
Arkoma Basin
Key Formation: Woodford
Drilling Locations: 811
Woodford Daily Production: 4.1 Mboe/d
Note: Proved reserves as of 12/31/13. Daily production pro forma for Sabine acquisition.
[1] Based on midpoint of 2014 production guidance.
Jones Energy Total
Proved Reserves: 89.0 MMBoe
Drilling Locations: 2,542
Net Acres: ~115,000 (~80% HBP)
Daily Production: 20.4 MBoe/d
Austin
Canadian
McAlester
13.3
17.0
22.5
2012A 2013A 2014E [1]
Production (Mboe/d)
$136
$205
2012A 2013A
EBITDAX ($mm)
$782
$1,017
2012A 2013A
1P PV-10 ($mm)
Denotes field offices.
Recent Milestones
VNR JV: 350+ Woodford Locations
6th Woodford BP Agreement
$187.5mm IPO – (NYSE: JONE)
$193.5mm Acquisition of Sabine’s
Anadarko Assets
$500mm, 6.75% Debt Offering
5. Investment Highlights
Geographic focus
Low-cost leader
High caliber management team
Strong financial profile
Basin-centric operator
Anadarko and Arkoma focus
Driven by well level returns with liquids focus
Drilled 490+ horizontal wells
Best in class Cleveland and Woodford operator
Low cost structure leads to best-in-class returns
Experienced management
28% Management ownership
47% Financial sponsor ownership
4
High growth
Large drilling inventory
~$400 million in liquidity post-debt offering
2014 drilling program will be primarily funded from cash flow
2.7x Debt/LTM EBITDAX pro-forma for Sabine
10 rigs currently running
Proved reserves grew by 38% CAGR 2010-2013
Production grew by 45% CAGR 2010-2013[1]
2,500+ identified drilling locations
~80% HBP
Operations on ~80% of Cleveland and Woodford locations
[1] 2013 is pro forma for Sabine acquisition.
6. 25 Year Mid-Con Experts
System
Series /
Epoch
Chesterian
Meramecian
Osagean
Kinder-
hookian
Devonian
Upper
Devonian
Morrowan
Lower
Permian
Wolf-
campian
Pennsyl-
vanian
Virgilian
Missourian
Desmoi-
nesian
Generalized
Stratigraphic Column
Atokan
Missi-
ssippian
Cherokee
(Skinner / Pink Lime/
Red Fork)
Marmaton Group
(Glover / Big Lime/
Oswego)
Hugoton / Pontotoc
(Brown Dolomite)
Chase / Council Grove
Admire
Wabaunsee
Shawnee
Douglas
Tonkawa
Cottage Grove
Hoxbar / Hogshooter
Checkerboard
Cleveland
Atoka Lime
13 Finger Lime
Springer
Meramec Lime /
St. Louis
Osage Lime /
Osage Chert
Woodford
Hunton
Morrow
Kinderhook /
Sycamore Lime
GraniteWash
Mid-con Strat Column
Potential Horizontal Target
5
CumulativeHorizontalWellsDrilled
Tonkawa
Jones has drilled over 490 horizontal wells to date in 9 target formations
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014E
0
100
200
300
400
500
600
CumulativeHorizontalWellsDrilled
Tonkawa
3
Brown Dolomite
5 2 4 3 5 8 7 3 13 12 9 10 6 4 6 10 11
Morrow
3 16 4 3 14 24 17 21 4
Cleveland
1032 17 33 42 45 4 36 38 23 73
Woodford
2518 14 13
Granite Wash
5 2 9 8 4 0
Note: 2014E represents wells in current development plan. Totals by area represent wells drilled through 12/31/13.
Dornick Hills Shale
7. 2014 Development Plan
6
85%
13%
1% 1%
Cleveland Woodford
Tonkawa Other
72%
14%
6%
8%
Cleveland D&C Woodford D&C
Leasehold Other
74%
18%
2%
6%
Cleveland Woodford
Tonkawa Other
Gross Wells Net Wells Total Capex - $350mm
Projecting over 30% production growth in 2014
8
52
73
48
97
139
2009 2010 2011 2012 2013 2014E
Plays
Gross
Wells
Net
Wells
Cleveland 103.0 73.0
Woodford 25.0 11.0
Tonkawa 3.0 1.2
Other 8.0 0.8
Total 139.0 86.0
2014 Drilling Program Historical Gross Wells Spud
8. 0
1
2
3
4
5
6
7
8
9
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71
JonesClevelandRigCount
TotalWellCapex($mm)
Well by Spud Date
Drilling Cost
7
Best in Class Operator
Cleveland D&C Costs ($mm)
Completion CostRig Count
Jan. 2013 Jan. 2014July 2013
Enhanced Frack Trial
Median D&C: $3.2mm
Maintained cost discipline while increasing Cleveland rigs from 3 to 8 in 2013
Note: Median D&C of $3.2 million excludes first three wells drilled by new rigs brought on during 2013 to account for learning curve with new rigs.
9. 60%
49%
80%
80%
25%
15%
Marcellus - Super Rich
Utica - Liquids Rich
Niobrara - Wattenberg
Eagle Ford - Liquids Rich
Jones Cleveland
Marcellus - SW Liquids Rich
Utica - Wet Gas
Wolfcamp - N. Midland Horizontal
Bone Spring (1st & 2nd) - NM
Jones - Woodford
Eagle Ford - Oil Window
Yeso
Wolfcamp - S. Midland Horizontal
Cana Woodford Shale - Oil Window
Bakken Shale
Bone Spring (3rd) - TX
Wolfberry
Uinta - Green River
Marcellus - NE
Wolfcamp - N. Delaware Horizontal
Mississippian Horizontal - West
Uinta - Wasatch Horizontal
Three Forks
Uinta - Wasatch Vertical
Industry Cleveland
Marcellus - SW
Granite Wash - Liquids Rich Horizontal
Fayetteville Shale
Barnett Shale - Core
Cotton Valley Horizontal
Cana Woodford Shale
Horn River Basin
Barnett Shale
Pinedale
Barnett Shale - S. Liquids Rich
Piceance Basin Valley
Industry Woodford
Eagle Ford Shale - Dry Gas
Haynesville Share - Core LA / TX
Haynesville / Bossier Shale - NE TX
Best in Class Returns
8
Average IRR by Play
Note: Jones internal estimates for Cleveland and Woodford and Wall Street research for peers. Dotted lines presented for Jones Cleveland and Woodford represent the high end of expected IRRs included in the presented averages. IRRs from Wall Street
research may be calculated on a different basis than Jones internal estimates. IRRs for both Wall Street research and Cleveland and Woodford type curves based on an oil price of $103.07, $95.58, $88.84, $84.70, $82.40 and $80.82 for the years one
through six respectively and held flat thereafter and a gas price of $3.77, $3.99, $4.16, $4.28, $4.42, $4.83 for years one through six respectively and held flat thereafter.
10. 4. Vendor Management
Competition from multiple vendors
Active cost management
9
Keys to Jones’ Operational Success
Emphasis
on Cycle
Time
Fit for
Purpose
Geographic
Focus
Promotes
efficiencies,
cost control
and optimizes
returns Unconventional
Experience
Vendor
Management
3. Fit for Purpose
Rigs
Procedures
Completion design
2. Unconventional Experience
Drilled over 490 horizontal wells in 9
different targets
5. Emphasis on Cycle Time
Focus on efficiency from spud to first
production
Repeatable for Jones, but difficult for others to replicate
1. Geographic Focus
Best in class Midcontinent horizontal driller
11. 10
Cleveland Play Evolution: 1997-2005
Play Highlights
>2,500 vertical wells
>1,700 horizontal wells
3,300 prospective sections
Note: 4Q13 production pro-forma for Sabine acquisition.
HANSFORD
HUTCHINSON
ROBERTS
OCHILTREE
LIPSCOMB
HEMPHILL ROGER MILLS
CUSTER
DEWEY
WOODWARD
ELLIS
WET
SCHULTZ BROS. #5H
IP30: 2322 MCF/D
7 BOP/D
JOHN B DOYLE #6H
IP30: 4858 MCF/D
138 BOP/D
WHEAT #341-2H
IP30: 2730 MCF/D
14 BOP/D
PARKER #1
IP30: 1251 MCF/D
3 BOP/D
Jones Operating Strategy
2,000 ft lateral length
4 frack stages
8 Bbl/d average oil IP30
Jones Acreage
12. 11
Cleveland Play Today
Active Operators (24 Active Rigs)
(8) (4) (2)(4) (4) (2)
Others
Source: IHS, Drilling info, company presentations. Rig data as of January 2014.
Jones Operating Strategy
4,350 ft lateral length
20 frack stages
270 bl/d average oil IP30
HANSFORD
HUTCHINSON
ROBERTS
OCHILTREE
LIPSCOMB
HEMPHILL ROGER MILLS
CUSTER
DEWEY
WOODWARD
ELLIS
JOHN B DOYLE #703-15H
IP30: 2745 MCF/D
645 BOP/D
KELLN #65-2H
IP30: 1042 MCF/D
879 BOP/D
JONES TRUST #189-4H
IP30: 1296 MCF/D
684 BOP/D
MATHERS RANCH #1518-1H
IP30: 6052 MCF/D
435 BOP/D
BIG LAKE #102-2H
IP30: 5756 MCF/D
287 BOP/D
Jones Operated Rigs
Other Operators
Jones Acreage
13. -
100
200
300
400
500
600
700
800
12
Cleveland Inventory Continues to Grow
Location Capture Locations Drilled / Sold
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Crusader
Chalker
Exxon
Shattuck
Sabine
Opportunity set is large with play spanning >3,300 square miles
15. 0
5
10
15
20
25
30
35
$2.25-$2.50 $2.50-$2.75 $2.75-$3.00 $3.00-$3.25 $3.25-$3.50 $3.50-$3.75 $3.75-$4.00 $4.00+
WellCount(102)
Well Costs ($mm)
0
5
10
15
20
25
30
0-50 50-100 100-200 200-300 300-400 400-500 500-600 600-700 700-800 800-900 900-1000 1000+
WellCount(106)
IP 30 (Boe/d)
Notes:
[1] No ERD wells. Excludes wells in the enhanced frack trial.
[2] No ERD or Pilot wells. Excludes wells in the enhanced frack trial.
Strong IP 30’s and Low Costs Allow Us to Generate High Returns
Cleveland IP 30 Historical Data (2011-2013) [1]
Cleveland Well Costs Historical Data (2011-2013) [2]
14
3-Year Well Cost
Average: $3.24mm
3-Year IP30
Average: 504 Boe/d
16. Strategy
Liquids-focus
Best-in-class cost
Completion optimization
Expand existing relationships
Evaluate M&A
15
Woodford Overview
Highlights
Spud 51 horizontal wells
4.1 MBoe/d 4Q13 net
production
26.2 MMBoe proved reserves
Source: IHS, Drilling info, company presentations. Rig data as of March 2014.
Solid returns with running room
Active Operators
(6 Active Rigs)
(2) (1)
(1) (1)
(1)
Jones Acreage
BP Acreage
Vanguard Acreage
Jones Operated Rigs
Other Operators
Vanguard AMI
Pablo
Energy
Hughes
Pittsburg
Atoka
17. 16
Chesapeake
IP30 199 BOPD +
616 MCFD
Apache
IP30 364 BOPD +
1,277 MCFD
Apache
IP30 930 BOPD +
1,546 MCFD
Apache
IP30 552 BOPD +
783 MCFD
Source: IHS, Drilling info, company presentations. Rig data as of March 2014.
Tonkawa Overview
Active Operators
(12 Active Rigs)
(8) (2) (1) (1)
Provides incremental growth opportunity with 209 drilling locations
Key Well Results in
JONE 2014 Focus
Area
18. 17
Trusted Partner for Numerous Large E&P Companies
Company Active Formation History Total Remaining Locations
Cleveland
Partner since 2000,
157 wells drilled
273
Woodford
Partner since 2012,
10 wells drilled
350
Woodford
Partner since 2013,
5 wells drilled
12
Selected Active Partnerships
Historical Deals (Wells Drilled)
(12 Wells) (32 Wells) (3 Wells)(16 Wells)
Jones controls drilling and completion in all deals
(42 Wells)
19. Growth Potential in our Backyard
18
Mid-Con Focus drives scale and capability for opportunistic acquisitions
Best-in-Class Operations in Woodford provide huge upside
Completion Optimization continues to enhance results
Stacked Pay Zones on HBP acreage provide running room
