Howard Weil Energy Conference. March 23-27, 2014

Transcription

1 Howard Weil Energy Conference March 23-27, 2014

2 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 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 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 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. 1

3 Company Summary Canadian McAlester Anadarko Basin Key Formations: Cleveland and Tonkawa Drilling Locations: 1,731 Cleveland Daily Production: 13.2 MBoe/d Austin Arkoma Basin Key Formation: Woodford Drilling Locations: 811 Woodford Daily Production: 4.1 MBoe/d Jones Energy Total Proved Reserves: 89.0 MMBoe Drilling Locations: 2,542 Net Acres: ~115,000 (~80% HBP) Daily Production: 20.4 MBoe/d Note: Proved reserves as of 12/31/13. Cleveland daily production is 4Q13 production pro forma for Sabine acquisition. Denotes field offices. 2

4 Investment Highlights Geographic focus Basin-centric operator Anadarko and Arkoma focus Driven by well level returns Low-cost leader Drilled 490+ horizontal wells Best in class Cleveland and Woodford operator Low cost structure leads to best-in-class returns High growth Currently running 10 rigs in core operating areas Proved reserves grew by 38% CAGR Production grew by 45% CAGR [1] Strong financial profile 2014 drilling program will be primarily funded from cash flow Significant hedging program reduces commodity price sensitivity Debt/LTM EBITDAX less than 3x pro-forma for 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 28% Management ownership 47% Financial sponsor ownership [1] 2013 is pro forma for Sabine acquisition. 3

5 90 Year Legacy of Success in the Oil & Gas Industry A.V. Jones, Jr. Jon Rex Jones A.V. Jones begins work for Marland Oil Company Jon Rex Jones joins his father & brother in Albany Jones drills first horizontal well in the Texas Panhandle Sells Hansford Co. assets to Laredo for $75 million Acquires Crusader Energy Group for $240.5 million Acquires Chalker s Cleveland assets for $250 million Acquires Sabine s Anadarko assets for $193.5 million JONE Jones & Stasney form partnership and move to Albany, Texas Jonny Jones & Jones family form Jones Energy Sells Hoover Field to Newfield for $25 million Sells Shattuck Field to Noble for $292 million ($66 mm net) JV with Southridge to enter the Arkoma Woodford Play IPO s on the New York Stock Exchange (NYSE: JONE) 4

6 25 Year Mid-Con Experts Jones has drilled over 490 horizontal wells to date in 9 target formations System Lower Permian Mid-con Strat Column Series / Epoch Wolfcampian Generalized Stratigraphic Column Hugoton / Pontotoc (Brown Dolomite) Chase / Council Grove Admire Wabaunsee Brown Dolomite Morrow Virgilian Missourian Pennsylvanian Desmoinesian Atokan Granite Wash Shawnee Douglas Tonkawa Cottage Grove Hoxbar / Hogshooter Checkerboard Cleveland Marmaton Group (Glover / Big Lime/ Oswego) Cherokee (Skinner / Pink Lime / Red Fork) Atoka Lime 13 Finger Lime Cumulative Cumulative Horizontal Horizontal Wells Wells Drilled Drilled Cleveland Granite Wash Woodford 103 Morrowan Morrow Mississippian Devonian Chesterian Meramecian Osagean Kinderhookian Upper Devonian Dornick Hills Shale Springer Meramec Lime / St. Louis Osage Lime / Osage Chert Kinderhook / Sycamore Lime Woodford Hunton Tonkawa E Potential Horizontal Target Note: 2014E represents wells in current development plan per 4Q13 earnings presentation. Totals by area represent wells drilled through 12/31/13. 5

7 2014 Development Plan Projected 30% production growth in 2014 primarily funded through cash flow Gross Wells Net Wells Total Capex - $350mm 2% 5% 1% 13% 1% 1% 6% 8% 18% 14% 74% 85% 72% Cleveland Tonkawa Other Woodford Non-Operated Cleveland Tonkawa Woodford Other Cleveland D&C Leasehold Woodford D&C Other Area Gross Wells Net Wells Cleveland Woodford Tonkawa Non-Operated Other Total Operated and Non-Operated

8 2014 Blended Production Profiles Generate Attractive Returns Cleveland Single Well Profile [1] 1,000 1,000 Oil Wet Gas Total [2] IP Bbl/D Mcf/D Boe/D 30 Day IP Day IP Cum. Production MBbl MMcf MBoe 1 Year Year Year Bbl/d Mcf/d % Liquids 67% % Oil 35% Gross Well Cost ($mm) $3.1 Oil NGL Gas Year 10 Woodford Single Well Profile [1][3] 1,000 10,000 Oil Wet Gas Total [2] IP Bbl/D Mcf/D Boe/D 30 Day IP 7 3, Day IP 6 3, Cum. Production MBbl MMcf MBoe 1 Year Year 2 1, Year 2 1, Bbl/d 10 1,000 Mcf/d % Liquids [3] 26% % Oil 0% Gross Well Cost ($mm) $4.2 1 Oil NGL Gas Year 100 Notes: [1] Jones production profiles based on actual historical results in each area. [2] Includes oil, dry gas and NGL components. [3] Assumes ethane rejection. 7

9 Best in Class Operator Cleveland Operator Average Days Spud to Total Depth [1] Competitor Average = 28 Days Days % faster Jones A B C D E F G H I J K L M N O P Q Woodford Operator Average Days Spud to Total Depth [2] Days % faster 19 Competitor Average = 31 Days 10 0 Jones A B C D E F G H I J Note: Purple highlighted bars represent operators with active rigs in the play. Source: Smith Bits [1] Represents wells drilled since July 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. Includes operators with > 10 wells drilled. [2] Represents wells drilled since July 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. Includes operators with > 10 wells drilled. 8

10 Best in Class Returns Average IRR by Play 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 5% 40% 39% 37% 35% 32% 32% 32% 29% 29% 28% 28% 26% 26% 25% 24% 24% 24% 24% 23% 22% 19% 17% 17% 16% 16% 15% 13% 12% 49% 60% 57% 54% 51% 51% 49% 66% 66% 74% 73% 80% 80% 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. 9

11 Keys to Jones Operational Success Repeatable for Jones, but difficult for others to replicate 1. Geographic Focus Best in class midcontinent horizontal driller 2. Unconventional Experience Drilled over 490 horizontal wells in 9 different targets Emphasis on Cycle Time Geographic Focus 3. Fit for Purpose Rigs Procedures Completion design 4. Vendor Management Vendor Management Promotes efficiencies, cost control and optimizes returns Unconventional Experience Competition from multiple vendors Active cost management 5. Emphasis on Cycle Time Fit for Purpose Focus on efficiency from spud to first production 10

12 Cleveland Overview HANSFORD LIPSCOMB ELLIS WOODWARD OCHILTREE HUTCHINSON DEWEY ROBERTS HEMPHILL ROGER MILLS CUSTER Jones Operated Rigs Other Operators Jones Acreage High GOR Area Liquids Rich Fairway Active Operators (24 Active Rigs) Others (8) (4) (4) (2) (4) (2) Source: IHS, Drilling info, company presentations. Rig data as of January

13 Cleveland Inventory Continues to Grow Cleveland opportunity set is large with play spanning >3,300 square miles 800 Sabine Chalker Exxon Shattuck Crusader Location Capture Locations Drilled / Sold Jones has spent nearly $1 billion drilling wells, with thousands of wells still yet to be drilled Inventory continues to grow every year Currently acquiring additional leasehold within our core Cleveland footprint 12

14 Trusted Partner for Numerous Large E&P Companies Jones controls drilling and completion in all JDA s Selected Active Partnerships 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 Historical Deals (Wells Drilled) [1] (12 Wells) (16 Wells) (32 Wells) (3 Wells) (42 Wells) [1] JDA with BP in the Cleveland formation from 2003 to

15 Strong IP 30 s and Low Costs Allow Us to Generate High Returns Cleveland IP 30 Historical Data ( ) [1] 30 3-Year IP30 Average: 504 Boe/d 25 Well Count (106) IP 30 (Boe/d) Cleveland Well Costs Historical Data ( ) [2] Year Well Cost Average: $3.24mm Well Count (102) $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 $4.00+ Notes: [1] No ERD wells. Excludes wells in the enhanced frack trial. [2] No ERD or Pilot wells. Excludes wells in the enhanced frack trial. Well Costs ($mm) 14

16 Historical Cleveland Operating Data Lateral Length (Feet) [1] Rate of Penetration (Ft per day) [1] 532 3,476 3,600 3,586 3,854 3,948 4,088 4, ,381 2, , Frack Stages [1] Oil IP-30 (Bbl/d) [2] [1] Excludes ERD, Pilot and enhanced frack wells. [2] Excludes ERD and enhanced frack wells. 15

17 Woodford Overview Solid returns with enormous running room Jones Woodford Highlights >50 horizontal wells 26.2 MMBoe proved reserves 4.1 MBoe/d net production [1] Vanguard AMI Active Operators (6 Active Rigs) (2) (1) Pablo Energy (1) (1) (1) Other Operators Jones Strategy: Vanguard Acreage Drive strong returns by focusing on liquids-rich part of the play and maintaining low costs Frack trial could drive enhanced economics and additional scale Opportunity set is large given our existing relationships and acreage position Acquisitions could also provide opportunities to increase scale Source: IHS, Drilling info, company presentations. Rig data as of March [1] 4Q13 net production 16 Jones Operated Rigs Jones Acreage BP Acreage

18 Tonkawa Overview Provides incremental growth opportunity with 209 drilling locations Active Operators (12 Active Rigs) (8) JONE 2014 Focus Area (2) (1) (1) Apache IP BOPD MCFD Chesapeake IP BOPD MCFD Upland IP BOPD + 1,546 MCFD Upland IP BOPD + 1,277 MCFD Source: IHS, Drilling info, company presentations. [1] Selected producing wells chosen in order to show the broad range of results around Jones acreage. 17

19 Levers to Pull for Upside in 2014 Cleveland Leasehold acquisitions Farmout or M&A opportunities Ongoing completion optimization Tonkawa Leverage existing Cleveland footprint Benefit of being second mover Three well test in 2Q14 Woodford Expand existing relationships Farmout or M&A opportunities Ongoing completion optimization Other Marmaton potential Other Mid-Con horizontal targets Bolt-on acquisitions 18