Forward-Looking & Other Cautionary Statements

Transcription

1 UBS Global Oil and Gas Conference May 19, 2015

2 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 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

3 Who is Jones Energy? Experienced Operator Midcon focus for over 26 years Cost Leader Fit for purpose operations Trusted Partner Numerous strategic partnerships Steward of Capital History of value creation 2

4 Key Statistics NYSE Ticker: JONE Share Price: $9.85 Market Cap: Enterprise Value: $608 million $1.4 billion Anadarko Basin Key Formation: Cleveland Arkoma Basin Key Formation: Woodford Sponsor Ownership: Shares Outstanding: Production: 30% 61.7 million 26.4 MBoepd Austin Proved Reserves: MMBoe Field Office N o te: P r o v e d r eserves a s o f 1 2 / 3 1 / 1 4. A v e r a g e d a ily p r o d u c ti o n for 1 Q S h a r e p r ice a s o f M a y 1 5,

5 First Quarter 2015 Highlights 1Q15 Production of 26.4 Mboe/d More than 3,000 Boe/d above 4Q14 Cleveland AFE now below $2.65 MM Margins support additional rigs 33 stage wells performing as expected 12 drilled / 11 completed Borrowing base affirmed at $562.5 MM Liquidity of ~$500 MM 4

6 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

7 Midcontinent Activity Resilient Midcon activity has composed 20% of total US rig count throughout recent cycles 40% of Midcon rigs operated by private E&Ps 100% US Rig Activity by Region as a % of Total 90% 80% 70% 60% 50% 40% 30% 20% 10% Consistent Activity Across Multiple Price Cycles 0% Other Rockies Northeast North TX West TX and NM East TX/North LA Midcon Source: Rig Data, Tudor, Pickering, Holt & Co. D a ta a s o f A p ril 1 0,

8 Focused on the Cleveland in 2015 MBbls 1Q10 2Q10 3Q10 4Q10 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 3 rigs currently running Fourth rig by end of May (fifth rig to follow) >30% oil uplift achieved Frack optimization successful High HBP position ~2,500 Cleveland locations remain ` 2015 Drilling Targets JONE Acreage Jones Cleveland Locations Gross: 704 Net: wells to be drilled in 2015 to hold leases 2014 leasing added 21,000 net acres 1, Cleveland Gross Operated Oil Production 7

9 Days Reduced Cycle Time Improves Efficiency and Returns Significant improvement in cycle time since October Open hole completions driving further improvements ~50% improvement since Oct peak Spud to Sales Spud to Spud

10 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 Achieved Reductions: $1,150,000 $2.0 $1.0 Breakdown of Savings: Frack Services $487,000 Rig Rates $122,000 Downhole Equipment $84,000 Drilling Fluid $73,000 Directional Drilling $66,000 Fuel & Drayage $59,000 Cement & Services $45,000 Other Items $214,000 Total $1,150,000 $2.65 $- Previous AFE Current AFE "All-in" Cleveland AFE Achieved Cost Reductions 9

11 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 10

12 Impact of Cost Reductions on Returns IRR Well level IRRs for 2015 Cleveland drilling program Unhedged Cleveland Well Level IRRs $2.65 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. IRRs reflect JONE potential cost reductions. Strip as of April 15,

13 Cleveland Frack Optimization Successful Number of Frack Stages 60 Open Hole Completion 43 Perf and Plug Completion Sliding Sleeve Completion

14 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 Cumulative Oil vs. Frack Stages (at 280 days) Expected frack trial production 60 Actual frack trial production frack stages: Right answer for Cleveland Actual production Estimated production Effective Frack Stages 13

15 Oil Rate (bpd) Optimization Drives Oil Uplift 1, Oil Uplift Comparison EUR 20 stage 33 stage Oil (Mbbls) Gas (MMcf) NGL (Mbbls) Total (Mboe) % increase Days Stage Type Curve Production Data from Wells with Over 20 Stages Stage Type Curve 14

16 % 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% Oil IP90 (Boe/d) 15

17 $ in millions $ in thousands $ in thousands Oil Uplift Has Created Significant Value $270,000 investment translates to: $1,250,000 $1,750,000 in incremental oil revenue per location $475,000 $765,000 in incremental PV-10 value per location Value accelerates as oil price increases ~$1,500,000 oil revenue ~$600,000 PV-10 value Cleveland Well Cost Comparison Incremental Oil Revenue(1) Incremental PV-10 Value $3.0 $2.5 ~$270,000 increase $1,800 $1,600 $1,400 $1,200 $900 $800 $700 $600 $2.0 $1,000 $800 $500 $400 $1.5 $600 $400 $300 $200 $200 $100 $ stage well 33 stage well $0 $55 Strip $75 $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 April 15,

18 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 17

19 2014 LOE and G&A Costs Among the Best 1 2 JONE JONE $30 LOE per Boe $12 Cash G&A per Boe $25 $10 $20 $8 $15 $6 $10 $4 $5 $2 $0 $0 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. 18

20 Hedges Protect 2015 Revenue Projected Revenue Hedging Impact on 2015 Revenue 100% 80% Only ~5% change in total revenue due to hedges 60% 40% 20% 0% $60 oil / $3.25 gas $30 oil / $2 gas $10 oil / $1 gas Unhedged Revenue Hedge Gain 19

21 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 Undrawn credit facility as of April 15, Based on net debt as of year-end 2014 and full-year 2014 EBITDAX 20

22 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 21

23 APPENDIX

24 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 IP IP Cumulative Production Mbbl MMcf Mbbl Mboe 1 Year Year EUR % of Total 41% 33% 26% 100% 23

25 Tonkawa An Untapped Opportunity Drilled 6 wells in 2014 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 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 Tonkawa 2.9 million acres 24

26 Marmaton Shows Promise As Others Drill Ahead Marmaton lies just below 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 Average formation depth: Tonkawa: 7,500 feet Cleveland: 8,500 feet Marmaton: 9,000 feet 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 Completed geological study across 5 counties JONE Acreage 25

27 Able to Ramp Activity as Margins Dictate Wells Drilled Operational flexibility allows us to ramp activity up and down Drilling History by Formation Brown Dolomite Tonkawa Cleveland Granite Wash Dropped all rigs in 4Q08, but ramped activity in 2010 after prices recovered Reduced 2015 activity with focus on the Cleveland Morrow 60 Woodford

28 2015 Full Year Guidance and 2Q Production Guidance 2015E 2Q15E Total Production (MMBoe) Average Daily Production (MBoe/d) Oil (MBbls/d) Natural Gas (MMcf/d) NGLs (MBbls/d) 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) $

29 Hedge Positions Q 3Q 4Q 1Q 2Q 3Q 4Q Crude Swaps (Mbbl) 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 $4.37 NGLs (MBbl) Ethane Propane Iso Butane Butane N. Gasoline Total NGL Hedge Price ($/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 $

30 NGL Hedge Position Detail Q 3Q 4Q 1Q 2Q 3Q 4Q Mt. Belvieu NGLs (MBbl) Ethane Propane Iso Butane Butane N. Gasoline Sub-Total Mt. Belvieu 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 $1.85 Conway NGLs (MBbl) Ethane Propane Iso Butane Butane N. Gasoline Sub-Total Conway Hedge Price ($/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 $

31 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% 30