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Jones energy inc final

  1. 1. IPAA’s OGIS New York April 8, 2014
  2. 2. 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.
  3. 3. 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 OtherCleveland 20.4 MBoe/d (53% Liquids) 65% 20% 15% Woodford OtherCleveland Proved Reserves Average Daily Production Note: Proved reserves as of 12/31/13. Daily production pro forma for Sabine acquisition.
  4. 4. 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
  5. 5. 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.
  6. 6. 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 GraniteWash Mid-con Strat Column Potential Horizontal Target 5 CumulativeHorizontalWellsDrilled Tonkawa Jones has drilled over 490 horizontal wells to date in 9 target formations 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014E 0 100 200 300 400 500 600 CumulativeHorizontalWellsDrilled 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 1032 17 33 42 45 4 36 38 23 73 Woodford 2518 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
  7. 7. 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
  8. 8. 0 1 2 3 4 5 6 7 8 9 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 45 47 49 51 53 55 57 59 61 63 65 67 69 71 JonesClevelandRigCount TotalWellCapex($mm) Well by Spud Date Drilling Cost 7 Best in Class Operator Cleveland D&C Costs ($mm) Completion CostRig Count Jan. 2013 Jan. 2014July 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.
  9. 9. 60% 49% 80% 80% 25% 15% Marcellus - Super Rich Utica - Liquids Rich Niobrara - Wattenberg Eagle Ford - Liquids Rich Jones Cleveland Marcellus - SW Liquids Rich Utica - Wet Gas Wolfcamp - N. Midland Horizontal Bone Spring (1st & 2nd) - NM Jones - Woodford Eagle Ford - Oil Window Yeso Wolfcamp - S. Midland Horizontal Cana Woodford Shale - Oil Window Bakken Shale Bone Spring (3rd) - TX Wolfberry Uinta - Green River Marcellus - NE Wolfcamp - N. Delaware Horizontal Mississippian Horizontal - West Uinta - Wasatch Horizontal Three Forks Uinta - Wasatch Vertical Industry Cleveland Marcellus - SW Granite Wash - Liquids Rich Horizontal Fayetteville Shale Barnett Shale - Core Cotton Valley Horizontal Cana Woodford Shale Horn River Basin Barnett Shale Pinedale Barnett Shale - S. Liquids Rich Piceance Basin Valley Industry Woodford Eagle Ford Shale - Dry Gas Haynesville Share - Core LA / TX Haynesville / 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.
  10. 10. 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
  11. 11. 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
  12. 12. 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
  13. 13. - 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
  14. 14. 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 FrackTrial
  15. 15. 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 $4.00+ WellCount(102) Well Costs ($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+ WellCount(106) 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
  16. 16. 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
  17. 17. 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
  18. 18. 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)
  19. 19. 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