Capital One Securities, Inc. 8 th Annual Energy Conference December 12, 2013
Forward-Looking & Other Cautionary Statements 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 forwardlooking. 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 substantially all of the 2013 capital budget with operating cash flow, 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 forwardlooking 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 quarterly report on Form 10-Q for the quarter ended September 30, 2013 and other reports filed with the SEC, 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. 1
Company Summary Anadarko Basin Key Formation: Cleveland Drilling Locations: 1,718 Daily Production: 15.0 Mboe/d Canadian McAlester Austin Jones Energy Total Drilling Locations: 2,529 Net Acres: ~107,000 (~80% HBP) Daily Production: 21.9 MBoe/d Arkoma Basin Key Formation: Woodford Drilling Locations: 811 Daily Production: 3.3 Mboe/d Recent Milestones Chalker Acquisition: $250mm Vanguard JV: 350+ Woodford Locations 6 th BP Agreement: Arkoma Woodford $187.5mm IPO (NYSE: JONE) Sabine PSA - $195mm Note: Daily production, locations and acreage are pro forma for Sabine as of September 2013. 2
Investment Highlights Geographic focus Basin-centric operator Anadarko and Arkoma focus Oil and liquids focus Low-cost leader Drilled 450+ horizontal wells Best in class Cleveland and Woodford operator Cost structure drives strong returns and profitability High growth Currently operating 10 rigs Proved reserves grew by 58% CAGR 2010-2012 Production grew by 55% CAGR 2010-3Q13 Strong financial profile 2013 drilling program funded from operating cash flow $125 mm of liquidity post-sabine 2.5x Debt / LTM EBITDAX post-sabine Large drilling inventory 2,500+ identified drilling locations ~80% HBP Operations on ~80% of Cleveland and Woodford locations High caliber management team Experienced management 27% Management ownership 47% Financial sponsor ownership 3
Stacked Horizontal Drilling Targets System Lower Permian Mid-con Strat Column Series / Epoch Wolfcampian Generalized Stratigraphic Column Hugoton / Pontotoc (Brown Dolomite) Chase / Council Grove Admire Wabaunsee 25 Year Mid-Con Experts Brown Dolomite (v / hz) 118 wells 5 2 4 3 5 8 7 3 13 12 9 10 6 4 6 10 11 Morrow (v) Virgilian Shawnee Douglas 106 wells 3 16 4 3 14 24 17 21 4 Tonkawa Cottage Grove Missourian Pennsylvanian Desmoinesian Atokan Morrowan Chesterian Granite Wash Hoxbar / Hogshooter Checkerboard Cleveland Marmaton Group (Glover / Big Lime/ Oswego) Cherokee (Skinner / Pink Lime / Red Fork) Atoka Lime 13 Finger Lime Morrow Dornick Hills Shale Springer Jones History 452 Horizontal Wells 9 Horizontal Targets 313 wells Cleveland (hz) 2 17 33 42 45 4 36 38 23 73 Granite Wash (hz) 28 wells 5 2 9 8 4 Woodford (hz) Mississippian Meramecian Osagean Kinderhookian Meramec Lime / St. Louis Osage Lime / Osage Chert Kinderhook / Sycamore Lime 45 wells 18 14 13 Devonian Upper Devonian Woodford Hunton 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 2013E Potential Horizontal Target 4
Best in Class Operator Cleveland Operator Average Days Spud to Total Depth [1] Days 35 33 31 29 27 25 23 21 19 17 15 20% faster Competitor Average = 29 Days 23 Jones A B C D E F G H I J K L M N O Woodford Operator Average Days Spud to Total Depth [2] 50 40 Competitor Average = 33 Days Days 30 20 10 52% faster 16 0 Jones A B C D E F G H I J K L M N [1] Sourced from Smith Bits. Represents wells drilled since 2008 in Lipscomb and Ellis counties at a measured depth of 11,000 to 15,000. Wells with a spud to total depth > 60 days were excluded. [2] Sourced from Smith Bits. Represents wells drilled since 2008 in Hughes, Coal, and Pittsburg counties at a measured depth from 9,000 to 13,000. Wells with a spud to TD of >60 days were excluded. 5
Consistent Acquisition Track Record Major Acquisitions Year Company Purchase Price Summary CRUSADER ENERGY GROUP INC. 2009 $241 million Solidified Jones leading position in the Cleveland play Partnered with Metalmark Capital on acquisition Represented Jones largest transaction at the time 2011 $165 million New basin entry Exposure to the Arkoma Woodford play Acquired significant proved reserves 2012 $250 million Strengthened Jones leading position in the Cleveland play Acquired over 300 horizontal Cleveland and Tonkawa locations Largest transaction to date 2013 $195 million Acquired production and acreage that overlays existing Cleveland core Increases Cleveland locations and acreage by over 30% Attractive valuation Over $900 million of acquisitions since 2009 6
Growth Three Pronged Approach Frack Design Stacked Pays Geoscience Focus Asset Expansion Focused effort to aggressively drive Company growth New Ventures Acquisitions Cost Advantage Negotiated Sales 7
Asset Overview
Sabine Acquisition Overview Highlights Assets: 26,000 net acres focused in the Cleveland core 225 total drilling locations 3,400 Boe/d current net production 92 producing wells; 54% liquids Purchase Price: $195 million cash Reserves: 14.3 MMBoe 1P (59% liquids) Hedging: Hedged 90% of PDP Timing: Expected closing in late Dec 2013 Funding Source: Existing senior credit facility Significant Cleveland Location Capture: Direct overlay with existing core 186 Cleveland drilling locations 35% increase in Cleveland locations Low operational risk Outstanding Well Level Returns: High liquids reserve content Low drilling and completion cost Multiple stacked horizontal plays Strong Liquidity: 2.5x Debt / LTM EBITDAX $125 million liquidity Immediately Accretive to EPS and CFPS Attractive Valuation $13.64 per proved Boe $57,353 per flowing Boe 9
Cleveland Overview Acquired Sabine Existing Jones Liquid Rich Fairway High GOR Area Play Highlights >2,500 vertical wells >1,700 horizontal wells 3,300 prospective sections Jones Cleveland Highlights >300 horizontal wells >54 MMBoe proved reserves 14,000 Boe/d September production 10
Cleveland Activity Jones Operated Rigs Other Operators Active Operators (24 active rigs) Le Norman Energy Others (7) (4) (4) (3) (2) (4) Source: IHS, Drilling info, company presentations. Rig data as of November 2013. 11
Historical Cleveland Operating Data Lateral Length (feet) 3,854 3,948 4,088 4,260 Frac Stages 18 18 20 3,476 3,600 3,586 12 12 8 9 2,381 2,056 4 4 5 1,791 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Spud to Release (Days) Spud-to-Release & ROP 32 30 28 26 24 2004 2005 2006 2007 2008 2009 2010 2011 2012 YTD 500 450 400 350 Rate of Penetration (Ft. / Day) Oil IP-30 (Bbl/d) 246 240 208 215 130 109 94 8 20 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 278 12
Cleveland Inventory Growth Cleveland Inventory 2004-2013 800 Sabine (186 locations) 700 600 Chalker (238 locations) Drilling Locations 500 400 300 Exxon (234 locations) Shattuck (33 locations) Crusader (134 locations 200 100-2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Location Capture Locations Drilled / Sold 13
Cleveland Costs and Performance D&C Costs ($mm) Total Well Capex ($mm) $7.0 $6.0 $5.0 $4.0 $3.0 $2.0 $3.79mm $3.45mm $3.11mm Drilling Cost Completion Cost $4.00mm $1.0 $0.0 Dec. 12012 2 3 4 5 6 7 8 9 10 11 1213 14 15 1617 18 19 2021 22 23 2425 26 27Well 2829 by 30 Spud 31 32 Date 3334 35 36 3738 39 40 4142 43 44 4546 47 48 49 5051 52 53 5455 56 57 5859 Nov. 2013 60 Spud-to-Rig Release (Days) 60 50 Spud to Release Days Rolling Average Spud to Release (Days) 40 30 20 10 0 Dec. 12012 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Well 26 27by 28Spud 29 30 Date 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 Nov. 572013 58 14
Technical Renaissance Open Hole Completion System Cased + Perf Old New Multiple Type: Open Hole Completion System Cased + Perf Stages: 20 23 Clusters: N/A 69 (3/stage) 3.5x Spacing (ft): 210 60 Prop (MMlb): 1.5 6.9 4.6x Water (Mbbl): 42 117 2.8x Propped frack half-length (ft): 400 500 1.3x Fracture Area (ft 3 ) 16,000 69,000 4.3x 15
Tonkawa Overview Chesapeake IP30 139 BOPD + 339 MCFD Upland IP30 930 BOPD + 1,546 MCFD Apache IP30 552 BOPD + 783 MCFD Chesapeake IP30 172 BOPD + 238 MCFD Tonkawa provides incremental growth opportunity with 208 drilling locations Source: IHS, Drilling info, company presentations. [1] Selected producing wells chosen in order to show the broad range of results around Jones acreage. 16
Woodford Overview Vanguard AMI Jones Operated Rigs Other Operators Jones Acreage BP Acreage Vanguard Acreage Rig data as of October 31, 2013. 17
Pro Forma Asset Summary Proved Reserves Net Acres Current Net Production 17% 24% 16% 83% 76% 84% 84 MMBoe [1] 107,000 Net Acres 21,900 Boe/d Jones Sabine Acquisition Acquisition increases Cleveland reserves by over 30% and raises current production to over 21,000 Boe/d [1] Jones standalone proved reserves as of 12/31/12, less 15.5 MMBoe of proved undeveloped reserves attributable to Southridge agreement, plus Sabine acquisition reserves of 14.3 MMBoe as of 10/1/13; does not include any reserves added during 2013. 18
Pro Forma Capitalization Transaction to be funded through Jones existing senior credit facility Pro forma liquidity of $125 million Pro forma Debt / LTM EBITDAX at 2.5x Capitalization Acquisition Pro Forma ($mm) 9/30/2013 Adjustment 9/30/2013 Cash $ 23.1 - $ 23.1 Senior Credit Facility $ 278.0 $ 195.0 $ 473.0 Second Lien 160.0-160.0 Total Debt $ 438.0 $ 195.0 $ 633.0 Stockholder's Equity 634.8-634.8 Total Capitalization $ 1,072.8 $ 195.0 $ 1,267.8 Debt / LTM EBITDAX 2.1x 2.5x [1] Liquidity $ 245.1 $ 125.1 [1] Pro forma for Chalker acquisition. 19
Hedging Position as of 12/1/13 5,000 Crude Oil Swaps (Bbl/d) 40,000 Natural Gas Swaps (Mcf/d) 5,000 NGLs Swaps (Bbl/d) 4,500 35,000 4,500 4,000 4,000 30,000 3,500 3,500 3,000 25,000 3,000 2,500 20,000 2,500 2,000 15,000 2,000 1,500 1,500 10,000 1,000 1,000 500 5,000 500 - $91.12 $89.27 $87.49 $84.92 $4.87 $4.89 $5.00 $4.50 $29.27 $32.05 $49.82 $64.39 - - 2014 2015 2016 2017 2014 2015 2016 2017 2014 2015 2016 2017 Series1 Jones Sabine Swaps Series1 Jones SabineSwaps Series1 Jones SabineSwaps 20