IPAA’s OGIS New York April 8, 2014

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.

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 Other Cleveland

20.4 MBoe/d (53% Liquids)

65%

20%

15%

Woodford Other Cleveland

Proved Reserves Average Daily Production

Note: Proved reserves as of 12/31/13. Daily production pro forma for Sabine acquisition.

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

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.

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

Gra

nite

Wa

sh

Mid-con Strat Column

Potential Horizontal Target 5

Cum

ula

tive H

orizonta

l W

ells

Drille

d

Tonkawa

Jones has drilled over 490 horizontal wells to date in 9 target formations

19

88

19

89

19

90

19

91

19

92

19

93

19

94

19

95

19

96

19

97

19

98

19

99

20

00

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

E 0

100

200

300

400

500

600

Cum

ula

tive

Hori

zo

nta

l W

ells

Dri

lled

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

103 2 17 33 42 45 4 36 38 23 73

Woodford

25 18 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

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

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

Jones C

levela

nd R

ig C

ount

Tota

l W

ell

Capex (

$m

m)

Well by Spud Date

Drilling Cost

7

Best in Class Operator

Cleveland D&C Costs ($mm)

Completion Cost Rig Count

Jan. 2013 Jan. 2014 July 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.

60%

49%

80%

80%

25%

15%

Marcellus - Super RichUtica - Liquids Rich

Niobrara - WattenbergEagle Ford - Liquids Rich

Jones ClevelandMarcellus - SW Liquids Rich

Utica - Wet GasWolfcamp - N. Midland Horizontal

Bone Spring (1st & 2nd) - NMJones - Woodford

Eagle Ford - Oil WindowYeso

Wolfcamp - S. Midland HorizontalCana Woodford Shale - Oil Window

Bakken ShaleBone Spring (3rd) - TX

WolfberryUinta - Green River

Marcellus - NEWolfcamp - N. Delaware Horizontal

Mississippian Horizontal - WestUinta - Wasatch Horizontal

Three ForksUinta - Wasatch Vertical

Industry ClevelandMarcellus - SW

Granite Wash - Liquids Rich HorizontalFayetteville Shale

Barnett Shale - CoreCotton Valley Horizontal

Cana Woodford ShaleHorn River Basin

Barnett ShalePinedale

Barnett Shale - S. Liquids RichPiceance Basin Valley

Industry WoodfordEagle Ford Shale - Dry Gas

Haynesville Share - Core LA / TXHaynesville / 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.

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

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

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

-

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

4 4 5 8 9

12

18

12

18 20

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E

20

Lateral Length (Feet) [1]

Historical Cleveland Operating Data

13

Oil IP-30 (Bbl/d) [2]

Rate of Penetration (Ft per day) [1]

Frack Stages [1]

2,381

1,791

2,056

3,476 3,600 3,586

3,854 3,948

4,088 4,260

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

[1] Excludes ERD, Pilot and enhanced frack wells.

[2] Excludes ERD and enhanced frack wells.

410

393

354

426

448

428

462

478 473

532

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

8 20

109 94

130

208

246

215

240

270

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

60 F

rack T

rial

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+

Well

Co

un

t (1

02)

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+

Well

Co

un

t (1

06)

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

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

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

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)

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