Scotia Howard Weil Energy Conference March 2015
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, 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 capital budget, projected internal rates of return, results of our hedging program, the ability to fund the Company s 2015 capital expenditure budget largely with free cash, projections regarding total production, average daily production, percentage liquids, operating expenses, production taxes as a percentage of revenue, G&A expenses and capital expenditure levels for 2015. 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. The 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. 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 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 from the SEC and from the Jones Energy website. 1
Jones Energy Overview NYSE Ticker: JONE Share Price: $8.64 Market Cap: $530 million Anadarko Basin Key Formation: Cleveland Cleveland Production: 17.0 MBoe/d Enterprise Value: Shares Outstanding: Avg Daily Production: Proved Reserves: Liquidity: $1.4 billion 61.6 million 23.2 MBoepd 115.3 MMBoe ~$500 million Austin Arkoma Basin Key Formation: Woodford Woodford Production: 4.0 MBoe/d Field Office Note: Proved reserves as of 12/31/14. Average daily production for FY 2014. Liquidity and share price as of March 20, 2015. 2
Prepared for Today and Focused on the Future Laser focus on execution and cost ~25% AFE reduction since December 2014 Strong hedging protects 2015 & beyond ~90% of 2015 oil and gas volumes hedged Flexible drilling program High HBP position offers optionality Proven cost leader in the MidCon 2015 program focused on Cleveland Solid balance sheet Tapped capital markets in February 2015 3
Well Results Prove Cleveland is a World Class Resource Play Strong results across Jones Cleveland acreage Well Location 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 JONE Acreage 1 Top 10 Jones Cleveland wells by IP30 with first production since the beginning of 2014. 4
Solid Growth in 2014 Avg Daily Production EBITDAX MBoepd 25.0 20.0 15.0 10.0 5.0 17.0 23.2 $ in millions $350 $300 $250 $200 $150 $100 $50 $205.0 $301.4-2013 2014 $0 2013 2014 Proved Reserves Oil Reserves MMBoe 140.0 120.0 100.0 80.0 60.0 40.0 20.0-115.3 89.0 2013 2014 millions of barrels 30.0 25.0 20.0 15.0 10.0 5.0-27.7 16.7 2013 2014 5
Focused on the Cleveland in 2015 3 rigs currently running AFE has dropped ~25% since December 2014 Targeting addition of 2 rigs in 2Q15 >30% oil uplift achieved Frack optimization complete 33 stage OH completions provide uplift plus savings High HBP position >80% HBP Only 9 out of 65 wells will be drilled in 2015 to hold leases 2014 leasing added 21,000 net acres ~2,500 Cleveland locations remain ` 2015 Drilling Targets JONE Acreage Jones Cleveland Locations Gross: 704 Net: 477 6
Cost Reductions for 33 Stage Open Hole Wells $900,000 in cost reductions since 4Q 2014 $4.0 $3.8 AFE in millions $3.0 $2.0 $1.0 Achieved Reductions: $900,000 Key Categories: Frack Services 47% Rig Rates 29% Fuel 45% Cement 48% Bits 32% Drilling Fluid 32% $2.9 Targeted Reductions: $300,000 Key Categories: Frack Services 35% Rig Rates 10% Locations 30% Casing 25% $2.6 All-in Cleveland AFE Achieved Cost Reductions Targeted Reductions $- Previous AFE Current AFE Next Target AFE 7
Impact of Cost Reductions on Returns Cleveland Drilling and Completion AFE Current $2,650 $2,850 $3,100 $3,800 Price Well level internal rates of return $70.00 / $4.00 58% 48% 38% 21% $65.00 / $3.50 44% 36% 28% 15% $60.00 / $3.25 34% 27% 21% 10% $55.00 / $3.00 25% 20% 15% 6% $50.00 / $2.75 17% 13% 9% 3% Note: Based on JONE Cleveland decline curve. IRRs reflect JONE potential cost reductions. 8
Cleveland Frack Optimization Completed Number of Frack Stages 60 43 Open Hole Completion Perf and Plug Completion Sliding Sleeve Completion 33 20 20 8-12 12 4-5 2004-2006 2007-2009 2010 2011 2012 2013 2014 2015 9
Optimization Drives Oil Uplift 1,000 Oil Uplift Comparison Oil Rate (bpd) 100 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 10
Uplift Has Created Significant Value $270,000 investment translates to: >$1,200,000 in incremental oil revenue per location (at $55 WTI) >$450,000 in PV-10 value per location (at $55 WTI) Value accelerates as oil price increases Cleveland Well Cost Comparison Incremental Oil Revenue (1) Incremental PV-10 Value $ in millions $3.0 $2.5 $2.0 $1.5 ~$270,000 increase >$1,200,000 oil revenue $ in thousands $1,800 $1,600 $1,400 $1,200 $1,000 $800 $600 $400 >$450,000 PV-10 value $ in thousands $800 $700 $600 $500 $400 $300 $200 $200 $100 $1.0 20 stage well 33 stage well $0 $55 $65 $75 $0 $55 $65 $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. 11
Commodity Price Realizations - Steady and Predictable Better differentials than many other regions 2014 average differentials (inclusive of transport): Oil: ~$4 per bbl differential to WTI Gas: ~$0.70 per MMBtu differential to HH Oil gathering system for Cleveland production to begin service in 2Q15 Valero Pipeline Piper Arnett Cleveland Oil Gathering System JONE Acreage Reydon 12
LOE and G&A Costs Among the Best $30 LOE per Boe $12 Cash G&A per Boe $25 $10 $20 $8 $15 $6 $10 $4 $5 $2 $0 1 2 JONE 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 $0 1 2 JONE 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 Note: LOE and Cash G&A per Boe calculated on full-year 2014 basis. LOE excludes ad valorem and production taxes. Peers include AREX, BBG, BCEI, CRK, CRZO, CWEI, FANG, GDP, LPI, MHR, MPO, MTDR, PDCE, PQ, REN, REXX, ROSE, SFY, and SGY. 13
Hedges Support Value Hedges provide security in an uncertain commodity price environment ~90% of estimated 2015 oil and gas production hedged at $85/bbl and $4.50 per Mcf >70% of total production hedged through 2016 at similar prices 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Fair value of hedges as a % of market cap 1 JONE 2 3 4 5 6 7 8 9 10 11 13 14 15 17 18 19 20 Note: Peers include AREX, BBG, BCEI, CRK, CRZO, CWEI, FANG, GDP, LPI, MHR, MTDR, PDCE, PE, PQ, REXX, ROSE, SFY, and SGY. Market cap as of March 19, 2015. Fair value of hedges as of December 31, 2014. 14
Hedges Protect 2015 Revenue Hedging Impact on 2015 Revenue 100% 80% Only ~5% change in total revenue due to hedges Projected Revenue 60% 40% 20% 0% $60 oil / $3.25 gas $30 oil / $2 gas $10 oil / $1 gas Unhedged Revenue Hedge Gain 15
Ready for Market Opportunities with Strong Balance Sheet $500 million in available liquidity 1 90% of debt outstanding matures in >7 years 2.8x net debt/ebitdax for trailing twelve months 2 $600 Debt Maturities Summary $ in millions $500 $400 $300 $200 $100 $0 Undrawn credit facility 1 2015 2016 2017 2018 2019 2020 2021 2022 2023 1 Liquidity and undrawn credit facility as of March 20, 2015 2 Based on net debt as of year-end 2014 and full-year 2014 EBITDAX 16
Jones Energy Prepared for Today and Focused on the Future Mid-Continent Focus History of success for over 26 years Expertise creates opportunities Operational Excellence Fit for purpose operations A leader in cost management Solid Financial Position Plenty of liquidity; spending within cash flow Substantial hedges at favorable prices Focused on Value Creation Oil uplift drives returns Will ramp activity as returns dictate Substantial Footprint with Running Room Lots to do in our own backyard Stacked pays provide growth opportunities 17
APPENDIX
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 41.0% 33.1% 25.9% 100.0% 19
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 20
Tonkawa An Untapped Opportunity Drilled 6 wells in 2014 Tonkawa 2.9 million acres Target AFE of $3.5 million Drilling program halted due to oil drop Ready to scale when economics dictate Industry continues to derisk acreage Extensive vertical production footprint Over 500 horizontal wells drilled by industry Still underdeveloped compared to Cleveland Jones has identified 324 gross (190 net) locations as of year-end 2014 Over 3,000 additional play locations Cleveland technical expertise derisks future Tonkawa development Average formation depth: Tonkawa: 7,500 feet Cleveland: 8,500 feet Marmaton: 9,000 feet JONE Acreage 21
Marmaton Shows Promise As Others Drill Ahead Marmaton lies just below the Cleveland Majority of Jones Anadarko acreage lies within the Marmaton fairway Results by other operators indicate EURs and production profiles on par with other targets in the basin No locations booked in 1P Jones has identified 566 gross drilling locations (334 net) as of year-end 2014 Marmaton Lime 1.0 million acres Marmaton Sand 2.1 million acres Over 2,500 additional locations in play fairway Similar geology to Cleveland Often referred to as Lower Cleveland Average formation depth: Tonkawa: 7,500 feet Cleveland: 8,500 feet Marmaton: 9,000 feet Completed geological study across 5 counties JONE Acreage 22
Able to Ramp Activity as Margins Dictate Operational flexibility allows us to ramp activity up and down Brown Dolomite Tonkawa Cleveland Granite Wash 140 120 100 80 Drilling History by Formation Dropped all rigs in 4Q08, but ramped activity in 2010 after prices recovered Reduced 2015 activity with focus on the Cleveland Morrow 60 Woodford 40 20 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 23
2015 Full Year Guidance and 1Q Production Guidance 2015E 1Q15E Total Production (MMBoe) 7.9 8.7 2.15 2.25 Average Daily Production (MBoe/d) 21.7 23.7 24.0 25.0 Oil (MBbls/d) 6.6 7.1 7.4 7.6 Natural Gas (MMcf/d) 54.8 60.3 60.0 65.0 NGLs (MBbls/d) 6.0 6.6 6.6 6.8 Lease Operating Expense ($/Boe) $4.75 $5.25 Production/Ad Valorem Taxes (% of Revenue) 6.5% 7.5% Cash G&A Expense ($mm) $25.0 $28.0 Total Capital Expenditures $210.0 24
Hedge Positions 2015 2016 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Crude Swaps (Mbbl) 572 613 595 572 492 465 457 411 Hedge Price / Bbl $85.48 $82.93 $84.60 $84.05 $83.53 $83.67 $83.64 $83.35 Natural Gas Swaps (MMcf) 5,232 5,095 4,740 4,636 4,340 4,130 3,960 3,800 Hedge Price / Mcf $4.49 $4.41 $4.47 $4.45 $4.65 $4.45 $4.45 $4.37 NGLs (MBbl) Ethane 119 110 101 92 15 14 12 12 Propane 172 226 192 168 102 102 102 102 Iso Butane 18 15 15 12 6 6 4 - Butane 50 45 42 41 12 11 9 6 N. Gasoline 63 60 57 53 24 22 21 16 Total NGL 422 456 407 366 159 155 148 136 Hedge Price ($/gal) Ethane $0.27 $0.27 $0.27 $0.27 $0.21 $0.21 $0.21 $0.21 Propane $0.98 $0.85 $0.89 $0.93 $0.56 $0.56 $0.56 $0.56 Iso Butane $1.29 $1.23 $1.23 $1.25 $1.30 $1.30 $1.39 N/A Butane $1.21 $1.21 $1.21 $1.20 $1.26 $1.28 $1.32 $1.26 N. Gasoline $1.94 $1.94 $1.95 $1.95 $1.99 $1.88 $1.89 $1.82 25
NGL Hedge Position Detail 2015 2016 1Q 2Q 3Q 4Q 1Q 2Q 3Q 4Q Mt. Belvieu NGLs (MBbl) Ethane 59 55 50 46 - - - - Propane 42 42 39 39 - - - - Iso Butane 6 3 3 3 3 3 3 - Butane 17 15 15 16 6 6 6 3 N. Gasoline 27 24 24 23 18 18 18 13 Sub-Total Mt. Belvieu 151 139 131 127 27 27 27 16 Hedge Price ($/gal) Ethane $0.34 $0.34 $0.34 $0.34 N/A N/A N/A N/A Propane $1.01 $1.01 $1.01 $1.01 N/A N/A N/A N/A Iso Butane $1.55 $1.55 $1.55 $1.55 $1.48 $1.48 $1.48 N/A Butane $1.37 $1.36 $1.36 $1.31 $1.42 $1.42 $1.42 $1.42 N. Gasoline $2.04 $2.06 $2.06 $2.05 $2.09 $1.93 $1.93 $1.85 Conway NGLs (MBbl) Ethane 60 55 51 46 15 14 12 12 Propane 130 184 153 129 102 102 102 102 Iso Butane 12 12 12 9 3 3 1 - Butane 33 30 27 25 6 5 3 3 N. Gasoline 36 36 33 30 6 4 3 3 Sub-Total Conway 271 317 276 239 132 128 121 120 Hedge Price ($/gal) Ethane $0.20 $0.20 $0.20 $0.20 $0.21 $0.21 $0.21 $0.21 Propane $0.98 $0.81 $0.86 $0.90 $0.56 $0.56 $0.56 $0.56 Iso Butane $1.16 $1.16 $1.16 $1.15 $1.13 $1.13 $1.13 N/A Butane $1.13 $1.13 $1.13 $1.13 $1.11 $1.11 $1.11 $1.11 N. Gasoline $1.87 $1.87 $1.86 $1.87 $1.70 $1.70 $1.70 $1.70 26
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% 27
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 59% of voting power in Jones Energy, Inc. Class A Common Stock 41% of voting power in Jones Energy, Inc. Public Shareholders 59% of total economic interest of JEH LLC Jones Energy, Inc. (NYSE: JONE) 41% of total economic interest of JEH LLC Jones Energy Holdings, LLC (JEH LLC) 28