Forward-Looking & Other Cautionary Statements

Capital One Energy Conference December 10-11, 2014 Forward-Looking & Other Cautionary Statements The following presentation includes forward -lookin...
Author: Dwight Jenkins
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Capital One Energy Conference December 10-11, 2014

Forward-Looking & Other Cautionary Statements The following presentation includes forward -looking statements. These statements relate to future events, such as anticipated revenues, earnings, business strategies, competitive position or other aspects of our operations or operating results or the industries or markets in which we operate or participate in general. Actual outcomes and results may differ materially from what is expressed or forecast in such forward -looking statements. These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that may prove to be incorrect and are difficult to predict such as oil and gas prices; operational hazards and drilling risks; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas development projects; unsuccessful exploratory activities; unexpected cost increases or technical difficulties in constructing, maintaining or modifying company facilities; potential liability for remedial actions under existing or future environmental regulations or from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; general domestic and international economic and political conditions, as well as changes in tax, environmental and other laws applicable to Jones Energy’s business and other economic, business, competitive and/or regulatory factors affecting Jones Energy’s business generally as set forth in Jones Energy’s filings with the Securities and Exchange Commission (SEC). We caution you not to place undue reliance on our forward -looking statements, which are only as of the date of this presentation or as otherwise indicated, and we expressly disclaim any responsibility for updating such information. Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10 -K and other reports and filings with the SEC. Copies are available from the SEC and from the Jones Energy website .

1

Jones Energy Overview (NYSE: JONE)

NYSE Ticker:

JONE

Share Price:

$10.05

Market Capitalization:

~$500 million

Anadarko Basin Key Formations: Cleveland & Tonkawa Cleveland Production: 18.3 MBoe/d

Arkoma Basin Key Formation: Woodford Woodford Production: 4.0 MBoe/d

Enterprise Value:

~$1.2 billion

Total Outstanding Shares:

49.4 million

Albany

Austin Average Daily Production:

24.5 MBoepd

Proved Reserves:

89.0 MMBoe

Liquidity:

~$300 million

Note: Proved reserves as of 12/31/13. Average daily production for 3Q 2014. Liquidity as of 3Q14. Share price as of December 8, 2014.

Denotes field offices.

2

Prepared for Today and Focused on the Future  Solid 3Q results financially and operationally  Strong hedging protects 2015 & beyond 

~175% of 2015 PDP oil hedged (~$85/bbl)



>95% of 2016 production from PDP hedged

 Scalable drilling program enhanced by high HBP position in core plays 

Double digit production growth achievable with as little as 6 rigs running



Flexible drilling and completion contracts

 Most active driller in the Cleveland, greatest leverage to push down service costs  Strong liquidity and dry powder for deals 

$625 million borrowing base (~$300 million undrawn as of 3Q 2014)

 Horizontal development opportunities with play expansion and stacked pay potential

3

Significant Production and EBITDAX Growth in the Past Year Total Production

Oil Production

28.0

8.0

25.0

7.0

22.0

MBopd

MBoepd

6.0 19.0

16.0

5.0

4.0

13.0

3.0

10.0 7.0

2.0 3Q13

3Q14

3Q13

EBITDAX Growth

22.0

$100

18.0

$80

$ in millions

MBopd

Cleveland Production

14.0

10.0

$60

$40

6.0

$20

2.0

$3Q13

3Q14

3Q14

3Q13

3Q14

4

2014 YTD Capital Spending Summary  >80% of increased ‘14 spending driven by positive factors: 1.

2.



Increased average working interest 

Accounts for ~60% of additional spending



Very efficient use of additional capital



~$27 million in lease acquisition for 2014 YTD



Fantastic outcome resulting in significant value creation

74%

Expect 6+ wells to be drilled by year-end

CLEVELAND - $274MM WOODFORD - $53MM TONKAWA - $8MM LEASEHOLD AND OTHER - $34MM

Woodford drilling costs 



20x3 perf and plug wells and sliding sleeve wells

Increased Tonkawa activity 

3.

YTD CAPEX AS OF 3Q14 $369 MM

Learning curve related to deploying two new completion techniques 

2.

15%

Better than expected leasing opportunity

Other factors impacting spending: 1.

9% 2%

Cost over-runs for wells spud during 2Q, but significant improvements achieved in latter part of 2014

Full-year 2014 spending likely to total $515 million

5

Hedging Program Among the Best of Peer Group  Extensive hedging program provides security in an uncertain commodity price environment 100

2015 % oil hedged 75

50

25

0

100

2015 % gas hedged 75

50

25

0

Source: Citi, Factset Note: Peers included have forecasted 2015 production growth of 20% or greater as of November 2014; % hedged relative to consensus production forecasts as of November 2014.

6

2015 EBITDAX Protected from Most Price Risk  Jones’ strong hedge position mitigates the risk of continued commodity price declines 7% decline in total EBITDAX with hedges

100%

Relative EBITDAX

80%

55% decline in total EBITDAX without hedges in place

60%

40%

20%

0%

11/28 Strip

$60/$3.25 Non-Hedged

$50/$2.50

Hedged

Note: Scenario assumes a 6 rig Cleveland program and NYMEX 5-year strip prices as of November 28th, 2014. Figures are only for example purposes and do not constitute guidance or indicate 2015 capital plans.

7

The Anadarko Basin – Prolific History with Stacked Pay Potential  Stacked pay zones within concentrated footprint provide significant development opportunities Current Target Formations

Tonkawa Sandstone Lease Acreage: ~35,000 Spacing: 160 acre

Cleveland Sandstone Lease Acreage: ~152,000 Spacing: 128 acre

Marmaton Sandstone Lease Acreage: ~54,000 Spacing: 160 acre JONES ACREAGE

8

Anadarko Operations – Focused on the Cleveland  10 rigs currently running in 4Q 

9 Cleveland, 1 Tonkawa



Represents nearly 30% of total Cleveland industry activity with >30 rigs running in play

 Perf and plug and sliding sleeve wells both showing consistent oil uplift  Moving to 33 stage open-hole completions in 2015  2015 activity is highly scalable to move with changes in prices  Leasing continues to show very positive results 

JONES ACREAGE (YTD-2014 Leasing)

JONES ACREAGE (Pre-2014)

163 net Cleveland locations acquired year to date

 Multiple acquisition opportunities in the basin beginning to surface

9

Cleveland Frack Trial Results – Oil Uplift From Additional Frack Stages Comparison of Average Cumulative Oil Production & Oil Decline Curve

500

Bbl/Day

Sliding sleeve results tracking 20x3 oil uplift 20x3 incremental oil production continues to grow: ~10,150 bbls avg at 335 days 50

YEAR 1

5 0

90

180

11 Stage OH Average

YEAR 2 270

360

YEAR 3

450 540 630 Days of Production

20 Stage OH Average

720

20x3 Average

810

900

990

1080

Sliding Sleeve Average

10

Cleveland: Determining the Completion that Yields Top Returns 20 Stage Open-Hole

20x3 Perf and Plug

Sliding Sleeves

33 Stage Open-Hole

2010 - 2013

2013/14 frack trial

2H14 method

2015 opportunity

AFE: $3.3 million

AFE: $4.5 million

AFE: $4.3 million

AFE: $3.8 million

Advantage: Historically reliable method

Advantage: Maximizes frack density

Advantage: Verifiability of frack isolation

Advantage: Cost effective with new frack density

Drawback: Limits frack density

Drawback: Offset well impacts, no verifiable isolation

Drawback: Has required sand cleanouts, delays 1st production

Drawback: Uplift projected but theoretical until 1st well results

Evolution of frack optimization on Jones Energy Cleveland acreage

11

Significant Operational Flexibility Heading into 2015

 Potential to grow production while still preserving liquidity

Estimated Metrics(1)

6 Rig Program

8 Rig Program

Production Growth

10% - 15%

20% – 25%

Debt/EBITDAX

~3.1x

~3.0x

Liquidity

~$220 - $240

~$170 - $190

(as of 12/31/15)

($ in millions)

($ in millions)

EBITDAX Growth

Flat to Minimal

~2% - 7%

(1) Estimated metrics assume all rigs drilling Cleveland wells using $3.8 million AFE for 33 stage open-hole completions and NYMEX 5-year strip pricing as of November 28th and accounts for company’s current hedge position. Figures are only for example purposes and do not constitute guidance or indicate 2015 capital plans.

12

Consistent Inventory Growth in Core Cleveland over Multiple Years  JONE continues to expand Cleveland inventory well ahead of the pace of drilling 

Growth achieved through multiple avenues including active leasing, JDAs, and acquisitions

1000

Cleveland Drilling Inventory Growth

Cleveland Locations

800 Total Undrilled Locations Drilled Locations

600

New Locations 400

Cleveland inventory has nearly tripled since 2011 even with ~200 wells drilled during that period.

200

0

2011 YE

2012

2013

2014

2014 YTD

13

Cleveland Leasing Update  Nearly 21,000 net acres added year to date for ~$26.7 million (less then $1,300 per net acre) 

Total Cleveland net location additions YTD total 163 with an average WI of 77%



Still working to acquire additional locations before year end with multiple deals working

Recently acquired 5,120 net acres prospective for Cleveland with option to acquire 63,000 additional net acres

JONES ACREAGE (YTD-2014 Leasing) JONES ACREAGE (Pre-2014)

14

Expanding our Horizons via Geosciences  Growing opportunities through geoscience focus 

Hired Jeff Tanner to head up Geosciences team

 Mid-Continent has shown stacked pay opportunities in previously unexploited formations 

Tonkawa, Marmaton in very early stages for Jones



Stacked pay potential being evaluated both on HBP and non-op acreage



2015 will focus on identifying additional potential pay zones on Jones acreage

 Recently acquired acreage is prospective for multiple zones above and below Cleveland

15

Tonkawa – A More Oily Opportunity  Drilling program underway 

Drilled 5 wells using 20-stage cemented sliding sleeve



6th well spud and progressing



On track to achieve target well cost of $3.5 million, $1 million less than industry average

Tonkawa 2.9 million acres

Average formation depth: Tonkawa: 7,500 feet Cleveland: 8,500 feet Marmaton: 9,000 feet

 Numerous locations to drill with more being added through active leasing  Economics are being re-evaluated for current crude prices and expected service costs 

Tonkawa wells are ~50% crude



Liquids compose ~75% of average production stream



JONES ACREAGE

Results in early 2015

16

Marmaton Shows Promise As Others Drill Ahead 



Marmaton lies just below the Cleveland formation 

Majority of Jones Anadarko acreage lies within the Marmaton fairway



Results by other operators indicate EURs and production profiles on par with other targets in the basin

1.0 million acres

Average formation depth: Tonkawa: 7,500 feet Cleveland: 8,500 feet Marmaton: 9,000 feet

No locations booked as proved 



Marmaton Lime

Jones acreage currently holds 336 drilling locations

Marmaton Sand 2.1 million acres

Similar geology to Cleveland 

Numerous operators in the past have referred to the Marmaton as “Lower Cleveland” due to similarities



Current study underway to determine prospectivity

JONES ACREAGE

17

Jones Energy – Prepared for the Future Mid-Continent Focus  History of success through multiple commodity cycles for over 25 years  Expertise creates opportunities to acquire at favorable prices

Stacked Pay Zones  Multiple horizons available with Geosciences leading efforts to expansion  Concentrated acreage position provides operational efficiencies

Scalable Operations with Multiple Paths to Success  Multiple proven completion methods allow for price optimization  Flexibility in operational contracts allow for ramp up or down as needed

Operational Leader  “Fit for purpose” philosophy minimizes costs while producing results  Operating costs continue to be some of the lowest among peers

Focused on Creating Value  $800 million notional value hedges and strong liquidity support flexibility  Focus for 2015 remains on creating value, regardless of price environment 18

APPENDIX

2014 Full Year Guidance and 4Q Production Guidance

Full Year Total Production (MMBoe)[1]

8.4 - 8.8

Full Year Average Daily Production (MBoe/d)[1]

23.0 - 24.0

Fourth Quarter Total Production (MMBoe)[1] Fourth Quarter Average Daily Production (MBoe/d)[1]

2.25 - 2.30 24.5 – 25.0

% Oil & Natural Gas Liquids[1] % Oil[1] % Natural Gas Liquids[1]

54% - 57% 26% - 29% 27% - 29%

Lease Operating Expense ($/Boe) Production Taxes (% of Revenue)

$5.00 - $5.50 4.7%

G&A Expense ($mm)[2]

$28.0 - $30.0

[1] Company is in ethane rejection mode in the Woodford. Projections assume ethane rejection continues throughout 2014. [2] Excludes non-cash compensation expense

20

Lease Operating Expense Among the Lowest of Peer Group  Jones’ lease operating expense remains low compared to peers 

Top quartile performer through first nine months of 2014

 Further evidence of efficient operations and a direct benefit to gross margins LOE per Boe

$30.00

$25.00

$20.00

$15.00

$10.00

$5.00

$0.00 1

2

3 JONE 5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

Source: Factset Note: LOE per Boe shown for the third quarter of 2014; Peers include AREX, BBEP, BCEI, CRZO, CXO, FANG, GDP, GPOR, GST, HK, KOG, LPI, MHR, MPO, OAS, PDCE, PQ, PVA, REXX, ROSE, RRC, SD, SGY, SM, SN, UPL, WLL, and XEC.

21

Jones’ Commodity Price Realizations - Steady and Predictable  Steady, predictable differentials 

Ample midstream takeaway options in the Mid-Continent region

 Realizations compare favorably to infrastructure constrained regions 

Jones average oil differential to WTI (inclusive of transport) < $5 per Bbl



Jones average gas differential to HH has averaged < $0.75 per MMBtu

 Extensive hedging program locks in prices and returns for predictable cash flows Jones Commodity Differentials $5.20

$1.00

$0.90 $5.00

$0.80

$ per bbl

$0.60 $4.60

$0.50 $0.40

$4.40

$ per MMBtu

$0.70

$4.80

$0.30 $0.20

$4.20

$0.10 $4.00

$3Q13

4Q13

1Q14

Oil Differentials

2Q14

3Q14

Gas Differentials

22

Oil Gathering System for Cleveland Production  Recently signed 10 year oil gathering agreement with Monarch Oil Pipeline for capacity of up to 12,000 barrels per day on system expected to be in service 2Q15

 Benefits include: 

Reduced need for truck hauling services and logistical planning by Jones personnel



Greater flow assurance during inclement weather (versus trucking)



Potential for improvement in net oil pricing for wells tied to gathering system

LIPSCOMB Piper

ELLIS

Valero Pipeline

OCHILTREE Arnett

Monarch System ROBERTS HEMPHILL

Reydon

ROGER MILLS

Jones Acreage

23

Hedge Positions 2014 Q4 Crude Swaps (Mbbl)

2015 Q1

Q2

2016 Q3

Q4

Full year

531

572

583

595

572

1,809

$90.97

$85.48

$84.70

$84.60

$84.05

$83.81

5,480

5,232

4,665

4,470

4,366

12,630

$4.58

$4.49

$4.52

$4.52

$4.51

$4.68

Ethane (Mbbl)

166

119

110

101

92

53

Propane (Mbbl)

219

172

166

156

149

48

Iso Butane (Mbbl)

21

18

15

15

12

16

Butane (Mbbl)

72

50

45

42

41

38

N. Gasoline (Mbbl)

68

63

60

57

53

83

546

422

396

371

347

238

$0.24

$0.27

$0.27

$0.27

$0.27

$0.21

Propane ($/gal)

1.01

0.99

0.99

0.99

0.99

0.90

Iso Butane ($/gal)

1.33

1.30

1.24

1.24

1.26

1.32

Butane ($/gal)

1.25

1.22

1.22

1.22

1.21

1.28

N. Gasoline ($/gal)

2.05

1.96

1.96

1.96

1.96

1.90

Hedge Price / Bbl Natural Gas Swaps (MMcf) Hedge Price / Mcf NGLs

Total NGL (Mbbl) Hedge Price Ethane ($/gal)

24

Corporate Structure

Metalmark, Management & Other Investors

74.7% of total economic interest of JEH LLC

Public Shareholders Class B Common Stock

Class A Common Stock

74.7% of voting power in Jones Energy, Inc.

25.3% of voting power in Jones Energy, Inc.

Jones Energy, Inc. (NYSE: JONE)

25.3% of total economic interest of JEH LLC

Jones Energy Holdings, LLC (JEH LLC)

25

Up-C Structure Overview

 JONE went public using an Up-C structure 

Other recent energy IPOs with Up-C structure include:   

Athlon Energy Inc. Frank’s International N.V. Parsley Energy, Inc.

 Due to the Up-C structure, on its financial statements, JONE allocates its net income between controlling interest (public shareholders) and non-controlling interest (Metalmark, management, & other investors), separately reporting net income attributed to each  

Net income attributable to non-controlling interests represents the pre-IPO owners’ 74.7% interest in Jones Energy, Inc. Net income attributable to controlling interests represents the public’s 25.3% interest in Jones Energy, Inc.

 JONE reported income tax provision  

Reported income tax provision does not include Federal and Oklahoma income taxes on the income allocated to the non-controlling interest As a result, the reported income tax provision is substantially different than the statutory 35% corporate income tax rate on pre-tax income (see the income tax footnote of our 2013 10-K) 26

Forecasting JONE EPS

 The simplest way to forecast JONE EPS is on a 100% basis: Income before income tax - Income tax provision (36.5% of pre-tax income*) Net income Total Class A and B shares outstanding of 49,367,741 Net income on 100% basis Total Class A and B shares outstanding

= JONE EPS

 This method is an accurate way to forecast JONE EPS, even though the forecasted net income and income tax provision will not directly agree with JONE reported financials

27

Forecasting JONE EPS

 Alternatively, EPS can be calculated using net income attributable to controlling interests and Class A shares outstanding: Income before income tax on 100% basis - Pre-tax income attributable to non-controlling interests (74.7% of total pre-tax income) Pre-tax income attributable to controlling interests (25.3% of total pre-tax income) Pre-tax income attributable to controlling interests - Income tax attributable to controlling interests (36.5% of pre-tax income attributable to controlling interests*) Net income attributable to controlling interests Diluted Weighted Average Class A shares outstanding of 12,573,000 Net income attributable to controlling interests = JONE EPS Diluted Class A shares outstanding

 With this method, the forecasted income tax provision will not agree with JONE reported financials, but can be reconciled to the income tax provision allocated to controlling interest broken out in the income tax footnote in JONE SEC filings

28

Understanding JONE EPS Calculation on Reported Financial Statements Breakdown of JONE Income Tax Calculation ($ in millions, except per share data)

JONE Q3 2014 Income Statement

Income before income tax $ 58.1

($ in thousands, except per share data)

Income before income tax

Income tax provision

$ 58,101

(5,871)

Pre-tax income allocated to controlling interests 58.1 x 25.3% = 14.7

Pre-tax income allocated to noncontrolling interests 58.1 x 74.7% = 43.4 Taxes allocated to non-controlling interests:

Net income Net income attributable to noncontrolling interest

Net income attributable to controlling interest

52,230

(42,701)

9,529

Texas franchise tax (0.7)

Texas franchise tax[2] (0.1)

Federal and Oklahoma income taxes[1] 0.0

Federal and Oklahoma income taxes (5.1)

Sum of values in red box equates to income tax provision Income tax provision (5.9)

Weighted average shares outstanding: Basic Diluted

12,508 12,573

Basic and Diluted EPS

$ 0.76

[1] Federal

and Oklahoma income taxes on pre-tax income allocated to noncontrolling interests are not reflected within Jones Energy, Inc. financials [2]

Taxes allocated to controlling interests:

Texas franchise tax for controlling interest presented net of federal benefit

Net income $ 52.2 Net income attributable to noncontrolling interests $ 42.7

Net income attributable to controlling interests $ 9.5 Class A shares outstanding 12.5 Basic and Diluted EPS $ 0.76

29