TPH Hotter N Hell Energy Conference June 18, 2014

Transcription

1 TPH Hotter N Hell Energy Conference June 18, 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 Key Statistics IPO Date: July 29, 2013 Ticker: Exchange: JONE 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 June 9, 2014: $18.60 Market Capitalization: Enterprise Value: Liquidity Post-Debt Offering: ~$900 million ~$1,550 million ~$370 million Proved Reserves 6% Average Daily Production 12% 29% 65% 15% 73% Cleveland Woodford Other Cleveland Woodford Other 89 MMBoe (50% PDP / 56% Liquids) 21.5 MBoe/d (57% Liquids) Note: Proved reserves as of 12/31/13. Average daily production for Q

4 Company Summary Canadian Jones Energy Total Proved Reserves: 89.0 MMBoe Drilling Locations: 2,542 Net Acres: ~115,000 (~80% HBP) Daily Production: 21.5 MBoe/d Production (MBoe/d) McAlester Anadarko Basin Key Formation: Cleveland and Tonkawa Drilling Locations: 1,731 Cleveland Daily Production: 15.6 MBoe/d Arkoma Basin Key Formation: Woodford Drilling Locations: 811 Woodford Daily Production: 3.2 MBoe/d 2012A 2013A 2014E [1] EBITDAX ($mm) $205 Austin $136 Recent Milestones VNR JV: 350+ Woodford Locations 6 th Woodford BP Agreement $187.5mm IPO (NYSE: JONE) $193.5mm Acquisition of Sabine s Anadarko Assets $500mm, 6.75% Debt Offering 2012A 2013A 1P PV-10 ($mm) $1,017 $782 Denotes field offices. Note: Proved reserves as of 12/31/13. Daily production reflects Q reported results. [1] Based on midpoint of 2014 production guidance A 2013A

5 Investment Highlights Geographic focus Basin-centric operator Anadarko and Arkoma focus Driven by well level returns with a growing liquids component Low-cost leader Drilled 500 horizontal wells Best in class Cleveland and Woodford operator Low cost structure leads to best-in-class returns High growth 10 rigs running (7 Cleveland, 2 Woodford, and 1 Tonkawa) Proved reserves grew by 38% CAGR Production grew by 45% CAGR [1] Strong financial profile ~$370 million in liquidity post-debt offering 2014 drilling program will be primarily funded from cash flow 2.6x Debt/LTM EBITDAX 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 [1] 2013 is pro forma for Sabine acquisition. Experienced management 28% Management ownership 47% Financial sponsor ownership 4

6 Is Off To A Great Start Compared to the fourth quarter of 2013: EBITDAX is up 38% Crude oil production is up 37% Liquids production is up 29% Total production is up 19% All 20 of the Cleveland frack trial wells have been completed and 19 of the 20 have over 100 days of production history 18 of the 20 are performing at or above the historical type curve for oil Spud the first of the three Tonkawa test wells Average drilling days in the Cleveland formation are down to 19 days from the 2013 average of 22 days New company record achieved of just 12.6 days to reach TD

7 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) 6

8 E Granite Wash Cumulative Cumulative Horizontal Horizontal Wells Wells Drilled Drilled 25 Year Mid-Con Experts Jones has drilled 500 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 (wells drilled each year) Morrow Virgilian Shawnee Douglas Tonkawa Cottage Grove 400 Cleveland Missourian Hoxbar / Hogshooter Checkerboard Pennsylvanian Desmoinesian Atokan Cleveland Marmaton Group (Glover / Big Lime/ Oswego) Cherokee (Skinner / Pink Lime/ Red Fork) Atoka Lime 13 Finger Lime Granite Wash Woodford Mississippian Devonian Morrowan Chesterian Meramecian Osagean Kinderhookian Upper Devonian Morrow Dornick Hills Shale Springer Meramec Lime / St. Louis Osage Lime / Osage Chert Kinderhook / Sycamore Lime Woodford Hunton Tonkawa 25 3 Potential Horizontal Target Note: 2014E represents wells in current development plan. Totals by area represent wells drilled through 12/31/13. 7

9 2014 Development Plan Projecting over 30% production growth in 2014 Gross Wells Net Wells Total Capex - $350mm 18% 2% 6% 13% 1% 1% 14% 6% 8% 74% 85% 72% Cleveland Tonkawa Woodford Other Cleveland Tonkawa Woodford Other Cleveland D&C - $250mm Woodford D&C - $50mm Leasehold - $22mm Other - $28mm 2014 Drilling Program Historical Gross Wells Spud Plays Gross Wells Net Wells Cleveland Woodford Tonkawa Other Total E 8

10 How Jones Creates Unmatched Value in the Cleveland IRR 60% 60% Emphasis on Cycle Time Focus on efficiency from spud to first production 50% 40% 30% 20% These five elements create nearly $1 million in D&C savings resulting in unmatched well level returns 25% Vendor Management Competition from multiple vendors Active cost management Fit for Purpose Rigs, Procedures, and Completion design are tailored for the target Unconventional Experience Drilled 500 horizontal wells in 9 different targets 10% Geographic Focus Best in class Midcontinent horizontal driller 0% Competitors Jones 9

11 Cleveland Play Evolution: SCHULTZ BROS. #5H IP30: 2322 MCF/D 7 BOP/D HANSFORD LIPSCOMB ELLIS WOODWARD WET OCHILTREE HUTCHINSON WHEAT #341-2H IP30: 2730 MCF/D 14 BOP/D DEWEY ROBERTS PARKER #1 IP30: 1251 MCF/D 3 BOP/D HEMPHILL ROGER MILLS JOHN B DOYLE #6H IP30: 4858 MCF/D 138 BOP/D CUSTER Jones Acreage Play Highlights >2,500 vertical wells >1,700 horizontal wells 3,300 prospective sections Jones Operating Strategy ( ) 2,000 ft lateral length 4 frack stages 8 Bbl/d average oil IP30 10

12 Cleveland Play Today JOHN B DOYLE #703-15H IP30: 2745 MCF/D 645 BOP/D HANSFORD LIPSCOMB ELLIS WOODWARD JONES TRUST #189-4H IP30: 1296 MCF/D 684 BOP/D OCHILTREE BIG LAKE #102-2H IP30: 5756 MCF/D 287 BOP/D HUTCHINSON KELLN #65-2H IP30: 1042 MCF/D 879 BOP/D DEWEY ROBERTS Jones Operated Rigs Other Operators Jones Acreage HEMPHILL Sections with Enhanced Completions MATHERS RANCH #1518-1H IP30: 6052 MCF/D 435 BOP/D ROGER MILLS CUSTER Active Operators (27 Active Rigs) (7) (7) (5) (3) (1) (4) Source: IHS, Drilling info, company presentations. Rig data as of June Others Jones Operating Strategy (current) 4,350 ft lateral length 20 frack stages 270 Bbl/d average oil IP30

13 Cleveland Inventory Continues to Grow Opportunity set is large with play spanning >3,300 square miles 800 Sabine Chalker Exxon Shattuck Crusader Location Capture Locations Drilled / Sold 12

14 Frack Trial 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] 60 Oil IP-30 (Bbl/d) [2] E [1] Excludes ERD, Pilot and enhanced frack wells. [2] Excludes ERD and enhanced frack wells. 13

15 Well Count (102) Well Count (106) 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 IP 30 (Boe/d) Cleveland Well Costs Historical Data ( ) [2] 3-Year Well Cost Average: $3.24mm $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 Woodford Overview Solid returns with running room Highlights Spud >50 horizontal wells in Hughes Vanguard AMI Active Operators (6 Active Rigs) the Woodford Currently running a two rig Pittsburg (2) (1) program New wells are 16 to 20 frack Pablo Energy stages versus 10 to 14 prior (1) (1) 3.2 MBoe/d 1Q14 net production (1) 26.2 MMBoe proved reserves Strategy Liquids-focus Best-in-class cost Completion optimization Expand existing relationships Evaluate M&A Atoka Jones Operated Rigs Other Operators Jones Acreage BP Acreage Vanguard Acreage Source: IHS, Drilling info, company presentations. Rig data as of June

17 Tonkawa Overview Provides incremental growth opportunity with 209 drilling locations Key Well Results in JONE 2014 Focus Area Apache IP BOPD + 1,546 MCFD Apache IP BOPD MCFD Apache IP BOPD + 1,277 MCFD Chesapeake IP BOPD MCFD Tonkawa Play Outline Cleveland Play Outline Jones Acreage Other Operators Rigs Jones Rig Active Operators (10 Active Rigs) (6) (1) (1) (1) (1) Source: IHS, Drilling info, company presentations. Rig data as of June

18 Why Investors Should be Bullish on Jones Mid-Con Focus A history of success in the region has lead to the reputation as a partner of choice Expertise creates opportunities to acquire at favorable prices Best-in-Class Operations Continuous improvement and application of technology leads to better results Keen eye on cost management creates very competitive returns in our plays Completion Optimization New techniques are being tested to unlock additional value and provide for increased recoveries Stacked Pay Zones Multiple target horizons on HBP acreage can increase the total drilling inventory Making Money Makes Sense Management is focused on projects that reflect optimal capital allocation and create long-term shareholder value 17

19 APPENDIX

20 2014 Full Year Guidance and Q2 Production Guidance Full Year Total Production (MMBoe) [1] Full Year Average Daily Production (MBoe/d) [1] Second Quarter Total Production (MMBoe) [1] Second Quarter Average Daily Production (MBoe/d) [1] % Oil & Natural Gas Liquids [1] 54% - 57% % Oil [1] 26% - 29% % Natural Gas Liquids [1] 27% - 29% Operating Expenses ($/Boe) $ $4.75 Production Taxes (% of Revenue) 4.7% G&A Expense ($mm) [2] $ $30.0 Total Capital Expenditures ($mm) $350 Cleveland D&C $250 Woodford D&C $50 Other D&C $10 Leasehold & Other $40 [1] Company is in ethane rejection mode in the Woodford. Projections assume ethane rejection continues throughout [2] Excludes non-cash compensation expense 19

21 Bbl/d Bbl/d 2014 Blended Production Profiles Cleveland Single Well Profile [1] % Liquids 67% % Oil 35% Gas Shrink 31% NGL Yield (Bbls / MMcf) 114 Nymex Differential (Oil / Gas) ($5.66 / $0.55) NGL as % of Crude 33.5% 1, Oil Wet Gas Total [2] IP Bbl/D Mcf/D Boe/D 30 Day IP Day IP Cum. Production MBbl MMcf MBoe 1 Year Year Year , Mcf/d Fixed OpEx ($ / Month / Well) $2,520 Gross Well Cost ($mm) $3.1 Severance Tax - Oil 4.6% Severance Tax - Gas / NGL 7.6% Ad Valorem Tax 2.4% 10 Oil NGL Gas Year 10 Woodford Single Well Profile [1][3] % Liquids 26% 1,000 Oil Wet Gas Total [2] IP Bbl/D Mcf/D Boe/D 30 Day IP 7 3, Day IP 6 3, ,000 % Oil 0% Gas Shrink 15% NGL Yield (Bbls / MMcf) Cum. Production MBbl MMcf MBoe 1 Year Year 2 1, Year 2 1, Nymex Differential (Oil / Gas) ($3.02 / $0.81) NGL as % of Crude 43.0% 10 1,000 Mcf/d Fixed OpEx ($ / Month / Well) $2,761 Gross Well Cost ($mm) $4.2 1 Severance Tax - Oil 1.1% Oil NGL Gas Severance Tax - Gas / NGL 1.1% Ad Valorem Tax 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. 20

22 21 Cleveland Frack Trial Open Hole Completion System Cased + Perf Open Hole Completion System Cased + Perf Multiple Stages: Clusters: N/A 69 (3/stage) 3.5x Spacing (ft): Prop (MMlb): x Water (Mbbl): x Propped frack half-length (ft): x Fracture Area (ft 3 ) 16,000 69, x

23 Trusted Partner for Numerous Large E&P Companies Jones controls drilling and completion in all deals 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) (12 Wells) (16 Wells) (32 Wells) (3 Wells) (42 Wells) 22

24 Hedge Volumes Q2 Q3 Q4 Q1 Q2 Q3 Q4 Oil and Gas Swaps Crude Oil (Mbbl) Natural Gas (MMcf) 3,890 4,020 3,530 3,152 2,945 2,750 2,556 Conway NGLs (Mbbl) Ethane Propane Iso Butane Butane N. Gasoline Sub-Total Conway Mt. Belvieu NGLs (Mbbl) Ethane Propane Iso Butane Butane N. Gasoline Sub-Total Mt. Belvieu Natural Gas Basis (MMcf) ANR PEPL NNG NGPL Enable / CP East SS Total Basis 2,160 2,630 2,560 1,140 1,110 1,070 1,030 23

25 Hedge Pricing Q2 Q3 Q4 Q1 Q2 Q3 Q4 Oil and Gas Swaps Crude Oil ($ / Bbl) Natural Gas ($ / Mcf) Conway NGLs ($ / Gal) Ethane Propane Iso Butane Butane Natural Gasoline Mt. Belvieu NGLs ($ / Gal) Ethane Propane Iso Butane Butane Natural Gasoline Natural Gas Basis ($ / Mcf) ANR (0.36) (0.36) (0.37) (0.38) (0.38) (0.38) (0.38) PEPL (0.39) (0.39) (0.39) (0.39) (0.39) (0.39) (0.39) NNG (0.17) (0.17) (0.17) (0.17) (0.17) (0.17) (0.17) NGPL (0.33) (0.33) (0.33) (0.38) (0.38) (0.38) (0.38) Enable / CP East (0.18) (0.18) (0.18) SS (0.38) (0.38) (0.38)

26 Corporate Structure Metalmark, Management & Other Investors Public Shareholders Class B Common Stock 74.7% of voting power in Jones Energy, Inc. Class A Common Stock 25.3% of voting power in Jones Energy, Inc. 74.7% of total economic interest of JEH LLC Jones Energy, Inc. (NYSE: JONE) 25.3% of total economic interest of JEH LLC Jones Energy Holdings, LLC (JEH LLC)

27 Up-C Structure Overview JONE went public using an Up-C structure Other recent energy IPOs with Up-C structure include: Athlon Energy Inc. Frank s International N.V. Parsley Energy, Inc. Due to the Up-C structure, on its financial statements, JONE allocates its net income between controlling interest (public shareholders) and non-controlling interest (Metalmark, management, & other investors), separately reporting net income attributed to each Net income attributable to non-controlling interests represents the pre-ipo owners 74.7% interest in Jones Energy, Inc. Net income attributable to controlling interests represents the public s 25.3% interest in Jones Energy, Inc. JONE reported income tax provision Reported income tax provision does not include Federal and Oklahoma income taxes on the income allocated to the non-controlling interest As a result, the reported income tax provision is substantially different than the statutory 35% corporate income tax rate on pre-tax income (see the income tax footnote of our K)

28 Forecasting JONE EPS The simplest way to forecast JONE EPS is on a 100% basis: Income before income tax - Income tax provision (36.5% of pre-tax income*) Net income Total Class A and B shares outstanding of 49,362,913 Net income on 100% basis Total Class A and B shares outstanding = JONE EPS *Represents effective tax rate on net income attributable to controlling interests. This method is an accurate way to forecast JONE EPS, even though the forecasted net income and income tax provision will not directly agree with JONE reported financials

29 Forecasting JONE EPS Alternatively, EPS can be calculated using net income attributable to controlling interests and Class A shares outstanding: Income before income tax on 100% basis - Pre-tax income attributable to non-controlling interests (74.7% of total pre-tax income) Pre-tax income attributable to controlling interests (25.3% of total pre-tax income) Pre-tax income attributable to controlling interests - Income tax attributable to controlling interests (36.5% of pre-tax income attributable to controlling interests*) Net income attributable to controlling interests Diluted Class A shares outstanding of 12,512,000 Net income attributable to controlling interests Diluted Class A shares outstanding = JONE EPS *Represents effective tax rate on net income attributable to controlling interests. With this method, the forecasted income tax provision will not agree with JONE reported financials, but can be reconciled to the income tax provision allocated to controlling interest broken out in the income tax footnote in JONE SEC filings

30 Understanding JONE EPS Calculation on Reported Financial Statements JONE Q Income Statement ($ in thousands, except per share data) Breakdown of JONE Income Tax Calculation ($ in millions, except per share data) Income before income tax $ 10.6 Income before income tax Income tax provision Net income Net income attributable to non-controlling interest $ 10,644 (1,257) 9,387 (7,715) Pre-tax income allocated to non-controlling interests 10.6 x 74.7% = 7.9 Taxes allocated to noncontrolling interests: Texas franchise tax (0.2) Federal and Oklahoma income taxes [1] (0.0) Pre-tax income allocated to controlling interests 10.6 x 25.3% = 2.7 Taxes allocated to controlling interests: Texas franchise tax [2] (0.05) Federal and Oklahoma income taxes (1.0) Net income attributable to controlling interest Weighted average shares outstanding: Basic Diluted 1,672 12,500 12,512 Basic and Diluted EPS $0.13 [1] Federal and Oklahoma income taxes on pre-tax income allocated to non-controlling interests are not reflected within Jones Energy, Inc. financials [2] Texas franchise tax for controlling interest presented net of federal benefit Sum of values in red box equates to income tax provision Net income attributable to non-controlling interests $ 7.7 Income tax provision (1.3) Net income $ 9.4 Net income attributable to controlling interests $ 1.7 Class A shares outstanding 12.5 Basic and Diluted EPS $0.13