TPH 11 th Annual Hotter N Hell Energy Conference June 17, 2015
Forward-Looking & Other Cautionary Statements The following presentation includes forward -looking statements. These statements relate to future events, such as anticipated re venues, 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, including guidance regarding the timing and location of additional rigs, results of the Company's drilling program, 2015 capital budget, the projected drilling and completion cost savings and the resultant impact on 2015 ca pital budget, projected internal rates of return, results of our hedging program, the ability to fund the Company s 2015 capital expenditu re budget largely with free cash, projections regarding total production, average daily production, percentage liquids, operating expen ses, production taxes as a percentage of revenue, G&A expenses and capital expenditure levels for 2015. Actual outcomes and results may diffe r 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 exi sting or future environmental regulations or from pending or future litigation; limited access to capital or significantly higher cost of cap ital related to illiquidity or uncertainty in the domestic or international financial markets; general domestic and international economic an d 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 o f the date of this presentation or as otherwise indicated, and we expressly disclaim any responsibility for updating such informati on. The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantitie s 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 ar e used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definiti ons for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings. 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 drill ing services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actua l drilling results, including geological and mechanical factors affecting recovery rates. Estimates of resource potential and drilling locations may change significantly as Jones Energy 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. 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 f rom the SEC and from the Jones Energy website. 1
Jones Energy Value Today, Long-Term Growth Story Judicious Steward of Capital History of value creation Opportunity Rich Organic opportunities, JDAs, M&A Not your Average Operator Fit for purpose cost leader Expertise Built over 26 Years Established Mid-con expert Solid Financial Position $500 mm in liquidity and very hedged 25.0 20.0 15.0 10.0 5.0 0.0 30.0 25.0 20.0 15.0 10.0 5.0 0.0 Average Daily Production (MBoe/d) 2010 2011 2012 2013 2014 Proved Oil Reserves (MMBoe) 2010 2011 2012 2013 2014 2
Jones Energy Goals for 2015 Solidify Financial Position Manage Capital Spending Drive Down Well Costs Execute Optimized Completions Deliver on Production Expectations Identify and Capture Value Creation Opportunities Capital markets transactions have provided $500 million in liquidity CAPEX of $210 million (60% reduction) focused on Cleveland development Reduced AFE to $2.6 million (30% savings) two months ahead of target 33 Stage open-hole completions are tracking uplifted oil type curve 1 st Quarter 2015 production was ~1,500 Boepd above top of guidance Numerous potential options identified and under evaluation 3
First Quarter 2015 Highlights 1Q15 Production of 26.4 Mboe/d More than 3,000 Boe/d above 4Q14 Cleveland AFE now $2.6 MM Margins support additional rigs Anadarko Basin Cleveland Arkoma Basin Woodford 33 stage wells performing as expected 12 drilled / 11 completed Austin Borrowing base affirmed at $562.5 MM Liquidity of ~$500 MM Field Office 4
Cleveland is a World Class Resource Play Strong results across Jones Cleveland acreage Top wells on acreage from all four major acquisitions ExxonMobil Chalker Sabine Crusader TOP 10 JONE CLEVELAND WELLS 1 IP30 Well (Boe/d) Elmer Graves 615-1H 1,432 Peyton Ranch 417-1H 1,251 Kelln 65-2H 1,116 Buccaneers 11-2H 1,032 Hager Trust 616-2H 933 Robert Doyle B 614-3H 919 Robert Doyle B 614-4H 912 Peyton Ranch 417-2H 894 Elmer Graves 615-5H 838 Hager Trust 616-3H 825 Average 1,015 Well Location Acquisitions JONE Acreage 1 T o p 1 0 J o n e s C levelan d w ells b y I P 3 0 w ith first p r o d u c ti o n s ince the b e g inning o f 2 0 1 4. 5
1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 MBbls Focused on the Cleveland in 2015 4 rigs currently running Fourth rig added end of May Fifth rig to be added soon >30% oil uplift achieved Jones Cleveland Locations Gross: 704 Net: 477 Frack optimization successful High HBP position 9 wells to be drilled in 2015 to hold leases Recent Cleveland assessment identified 5,700 remaining locations not owned by JONE 1,200 800 400 0 ` 2015 Drilling Targets JONE Acreage Cleveland Gross Operated Oil Production 6
2015 Capital Spend Tracking to Budget $ in millions On track to spend $210 million in 2015, in-line with guidance Budget incorporates ramp from 3 to 5 rigs and reduction to current AFE of $2.6 million 2015 Capital Spending by Quarter $100 $80 $60 $40 $20 $0 Q1 Q2 Q3 Q4 Budget Actual 7
Cost Reductions for 33 Stage Open Hole Wells AFE in millions Over 30% in negotiated cost reductions since 4Q 2014 $4.0 $3.8 $3.0 $2.0 $1.0 Achieved Reductions: $1,200,000 Breakdown of Savings: Frack Services $487,000 Rig Rates $122,000 Downhole Equipment $96,000 Casing $81,000 Drilling Fluid $73,000 Directional Drilling $66,000 Fuel & Drayage $59,000 Cement & Services $45,000 Other Items $171,000 Total $1,200,000 $2.6 $- Previous AFE Current AFE "All-in" Cleveland AFE Achieved Cost Reductions 8
How Jones Creates Unmatched Value in the Cleveland Average Cleveland AFEs - Jones vs. Competitors Geographic Focus Best in class Midcontinent horizontal driller Unconventional Experience Drilled over 600 horizontal wells in 9 different targets Five elements create over $1 million in savings resulting in unmatched returns Fit for Purpose Rigs, procedures, and completion design are tailored for the target Vendor Management Competition from multiple vendors Active cost management Competitors Jones Emphasis on Cycle Time Focus on efficiency from spud to first production 9
Extremely Competitive Return in the Cleveland IRR Current IRRs reflect NYMEX strip pricing as of June 10 th for all commodities Unhedged Cleveland Well Level IRRs $2.6 MM AFE 90% 80% 70% 60% 50% 40% 30% 20% 10% $3,400 $3,100 $2,800 $2,500 - $2,200 Well Cost ($ thousands) Strip +20% Strip +10% Strip Strip -10% Note: Based on JONE Cleveland decline curve. Strip as of June 10, 2015. See appendix for forward pricing by commodity. 10
33 Frack Stages: Ideal Cleveland Density Avg Cumulative Oil (Mbbl) Strong correlation between frack stages and cumulative oil production 33 stages is appropriate frack density for Cleveland 50 45 40 35 30 Cumulative Oil vs. Frack Stages (at 280 days) 43 33 43 60 Expected frack trial production 60 Actual frack trial production 25 20 15 20 33 frack stages: Right answer for Cleveland Actual production Estimated production 10 5 0 0 10 20 30 40 50 60 Effective Frack Stages 11
Oil Rate (bpd) Optimization Drives Oil Uplift 1,000 100 Oil Uplift Comparison EUR 20 stage 33 stage Oil (Mbbls) 81 112 Gas (MMcf) 541 545 NGL (Mbbls) 70 71 Total (Mboe) 241 274 +38% increase 10 0 50 100 150 200 250 300 350 Days 2015 20 Stage Type Curve Production Data from Wells with Over 20 Stages 2015 33 Stage Type Curve 12
% of wells with given IP90 Increased Oil with Greater Predictability Increased frack density means more oil and more predictable results Only 30 Cleveland wells required to achieve type curve 16% Cleveland Oil IP90 14% 12% 10% 8% 20 Stages > 20 Stages 6% 4% 2% 0% 0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 600 640 680 Oil IP90 (Boe/d) 13
$ in millions $ in thousands $ in thousands Oil Uplift Has Created Significant Value $230,000 investment translates to: $1,225,000 $1,725,000 in incremental oil revenue per location $515,000 $815,000 in incremental PV-10 value per location Value accelerates as oil price increases ~$1,525,000 oil revenue ~$650,000 PV-10 value $3.0 $2.5 $2.0 $1.5 $1.0 Cleveland Well Cost Comparison ~$230,000 increase 20 stage well 33 stage well Incremental Oil Revenue(1) $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 $55 Strip $75 Incremental PV-10 Value $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 $55 Strip $75 (1) Incremental oil revenue for a 33 stage open-hole well as compared to a 20 stage open-hole well for full productive life of the well. Assumes 2015 Cleveland type curve. Strip as of June 10, 2015. See appendix for forward pricing by commodity. 14
The Anadarko Basin Prolific History with Stacked Pay Potential Stacked pay zones provide significant development opportunities Current Target Formations Tonkawa Sandstone Lease Acreage: ~122,000 Gross Locations: 324 Cleveland Sandstone Lease Acreage: ~163,000 Gross Locations: 704 Marmaton Sandstone Lease Acreage: ~97,000 Gross Locations: 566 JONE Acreage 15
Hedges Through 2019 Significant hedges protect revenue stream and lock in returns 180% 160% 140% 120% 100% 80% 60% 40% 20% 0% % of PDP Hedged by Product 2015 2016 2017 2018 1Q19 Oil Gas NGLs Note: Percentages based on PDP as of 1Q15. 16
Ready for Market Opportunities with Strong Balance Sheet $ in millions $562.5 million borrowing base reaffirmed ~$500 million in liquidity ~90% of debt outstanding matures in >7 years 2.8x net debt/ebitdax for trailing twelve months 2 $600 Debt Maturities Summary $500 $400 $300 $200 $100 $0 Undrawn credit facility 1 2015 2016 2017 2018 2019 2020 2021 2022 2023 1 Undrawn credit facility as of April 15, 2015 2 Based on net debt as of year-end 2014 and full-year 2014 EBITDAX 17
Jones Energy Prepared for Today and Focused on the Future Mid-Continent Focus Operational Excellence Solid Financial Position Focused on Value Creation Substantial Footprint with Running Room 18
APPENDIX
Strip Pricing as of June 10, 2015 All return calculations incorporate: Crude oil and natural gas strip pricing as of June 10, 2015 NGL basket projected using relationship to crude by component Incorporates forward indications of NGL prices from hedge counterparties Remainder of 2015 2016 2017+ WTI Crude Oil ($ / Bbl) $62.54 $64.00 $65.24 NYMEX Natural Gas ($ / Mcf) $2.95 $3.18 $3.31 NGLs (Conway) ($ / Gal)* Barrel components Ethane 37% $0.16 $0.16 $0.16 Propane 34% $0.43 $0.51 $0.54 Butane 12% $0.58 $0.64 $0.66 Iso Butane 5% $0.57 $0.63 $0.65 Nat. Gasoline 12% $1.28 $1.31 $1.31 NGL Barrel 100% $0.45 $0.49 $0.50 NGL Barrel as a % of Crude 30% 32% 32% *All Cleveland NGL production receives Conway pricing. 20
2015 Cleveland Type Curve Key statistics shown below for 2015 Cleveland type curve (274 Mboe EUR) Cleveland 3P EUR of 305 Mboe, but with a higher gas component Key Statistic: Oil Gas NGL Total IP Bbl/d Mcf/d Bbl/d Boe/d IP30 228 641 83 418 IP90 189 612 80 371 Cumulative Production Mbbl MMcf Mbbl Mboe 1 Year 36 141 18 78 5 Year 68 294 38 155 EUR 112 545 71 274 % of Total 41% 33% 26% 100% 21
2015 Full Year Guidance and 2Q Production Guidance 2015E 2Q15E Total Production (MMBoe) 7.9 8.7 2.05 2.15 Average Daily Production (MBoe/d) 21.7 23.7 22.5 23.5 Oil (MBbls/d) 6.6 7.1 6.7 7.0 Natural Gas (MMcf/d) 54.8 60.3 57.0 60.0 NGLs (MBbls/d) 6.0 6.6 6.3 6.6 Lease Operating Expense ($/Boe) $4.75 $5.25 Production/Ad Valorem Taxes (% of Unhedged Revenue) 6.5% 7.5% Cash G&A Expense ($mm) $25.0 $28.0 Total Capital Expenditures ($mm) $210.0 22
Hedge Positions 2015 2016 2Q 3Q 4Q 1Q 2Q 3Q 4Q Crude Swaps (Mbbl) 613 595 572 492 465 457 411 Hedge Price / Bbl $82.93 $84.60 $84.05 $83.53 $83.67 $83.64 $83.35 Natural Gas Swaps (MMcf) 5,095 4,740 4,636 4,340 4,130 3,960 3,800 Hedge Price / Mcf $4.41 $4.47 $4.45 $4.65 $4.45 $4.45 $4.37 NGLs (MBbl) Ethane 110 101 92 15 14 12 12 Propane 226 192 168 160 146 135 126 Iso Butane 15 15 12 6 6 4 - Butane 45 42 41 12 11 9 6 N. Gasoline 60 57 53 24 22 21 16 Total NGL 456 407 366 217 199 181 160 Hedge Price ($/gal) Ethane $0.27 $0.27 $0.27 $0.21 $0.21 $0.21 $0.21 Propane $0.85 $0.89 $0.93 $0.55 $0.55 $0.55 $0.56 Iso Butane $1.23 $1.23 $1.25 $1.30 $1.30 $1.39 N/A Butane $1.21 $1.21 $1.20 $1.26 $1.28 $1.32 $1.26 N. Gasoline $1.94 $1.95 $1.95 $1.99 $1.88 $1.89 $1.82 23
NGL Hedge Position Detail 2015 2016 2Q 3Q 4Q 1Q 2Q 3Q 4Q Mt. Belvieu NGLs (MBbl) Ethane 55 50 46 - - - - Propane 42 39 39 - - - - Iso Butane 3 3 3 3 3 3 - Butane 15 15 16 6 6 6 3 N. Gasoline 24 24 23 18 18 18 13 Sub-Total Mt. Belvieu 139 131 127 27 27 27 16 Hedge Price ($/gal) Ethane $0.34 $0.34 $0.34 N/A N/A N/A N/A Propane $1.01 $1.01 $1.01 N/A N/A N/A N/A Iso Butane $1.55 $1.55 $1.55 $1.48 $1.48 $1.48 N/A Butane $1.36 $1.36 $1.31 $1.42 $1.42 $1.42 $1.42 N. Gasoline $2.06 $2.06 $2.05 $2.09 $1.93 $1.93 $1.85 Conway NGLs (MBbl) Ethane 55 51 46 15 14 12 12 Propane 184 153 129 160 146 135 126 Iso Butane 12 12 9 3 3 1 - Butane 30 27 25 6 5 3 3 N. Gasoline 36 33 30 6 4 3 3 Sub-Total Conway 317 276 239 190 172 154 144 Hedge Price ($/gal) Ethane $0.20 $0.20 $0.20 $0.21 $0.21 $0.21 $0.21 Propane $0.81 $0.86 $0.90 $0.55 $0.55 $0.55 $0.56 Iso Butane $1.16 $1.16 $1.15 $1.13 $1.13 $1.13 N/A Butane $1.13 $1.13 $1.13 $1.11 $1.11 $1.11 $1.11 N. Gasoline $1.87 $1.86 $1.87 $1.70 $1.70 $1.70 $1.70 24
NGL Barrel Component Detail Cleveland Conway (80% of forecasted 2015 NGL production) Basket Ethane 37% Propane 34% Butane 12% Iso Butane 5% Natural Gasoline 12% Cleveland Natural Gasoline 12% Iso Butane 5% Butane 12% Propane 34% Ethane 37% Woodford Mont Belvieu (20% of forecasted 2015 NGL production) Basket Ethane* 13% Propane 45% Butane 19% Iso Butane 5% Natural Gasoline 18% *Assumes ethane rejection in the Woodford Woodford Natural Gasoline 18% Iso Butane 5% Butane 19% Propane 45% Ethane 13% 25
Corporate Structure Updated for recent capital markets transactions Stock trading liquidity has improved significantly post-recent transactions Metalmark, Management & Other Investors Class B Common Stock 50.9% of voting power in Jones Energy, Inc. Class A Common Stock 49.1% of voting power in Jones Energy, Inc. Public Shareholders 50.9% of total economic interest of JEH LLC Jones Energy, Inc. (NYSE: JONE) 49.1% of total economic interest of JEH LLC JONE company ownership summary Metalmark 30% Jones Family and Management 22% JVL Advisors 9% GSO Capital Partners 4% Magnetar Capital 4% Remaining Shareholders 32% Total 100% Jones Energy Holdings, LLC (JEH LLC) 26