Exhibit 99.1

JONES ENERGY, INC. MANAGEMENT PRESENTATION AUGUST 2018 HIGHLY CONFIDENTIAL

Disclaimers This presentation has been prepared by Jones Energy, Inc. (the “Parent” and, collectively with its subsidiaries, the “Company”) for the exclusive use of the party to whom the Company delivers this presentation (such party, together with its subsidiaries and affiliates, the “Recipient”). This presentation does not constitute or form part of, and should not be construed as, any offer, invitation or recommendation to purchase, sell or subscribe for any securities in any jurisdiction and neither the issue of the presentation nor anything contained herein shall form the basis of or be relied upon in connection with, or act as an inducement to enter into, any investment activity. This presentation does not purport to contain all of the information that may be required to evaluate any investment in the Company or any of its securities, including the guarantees issued by the Parent and certain of its subsidiaries, and should not be relied upon to form the basis of, or be relied on in connection with, any contract or commitment or investment decision whatsoever. The Recipient should not construe the contents of this presentation as legal, tax, accounting, investment or other advice or a recommendation. The merit and suitability of an investment in the Company should be independently evaluated and any person considering such an investment in the Company is advised to obtain independent advice as to the legal, tax, accounting, financial, credit and other related advice prior to making an investment. Any decision to purchase securities in any offering the Company may make in the future should be made solely on the basis of information contained in any prospectus or offering circular that may be published by the Company in final form in relation to any such proposed offering and which would supersede this presentation and information contained herein in its entirety. To the extent available, the industry and market data contained in this presentation has come from official or third party sources. Third party industry publications, studies and surveys generally state that the data contained therein have been obtained from sources believed to be reliable, but that there is no guarantee of the accuracy or completeness of such data. While the Company believes that each of these publications, studies and surveys has been prepared by a reputable source, the Company has not independently verified the data contained therein and makes no representation or warranty as to the accuracy, completeness or reasonableness of such information. The Recipient acknowledges that the Company considers this presentation and all information contained herein to be confidential, sensitive and proprietary information that is “Confidential Information” subject to the Confidentiality Agreement executed by the Parent and the Recipient on or about August 15, 2018. The Recipient agrees that it shall in accordance with its established procedures keep the presentation and all information contained herein confidential and shall not use any such information for any purpose. The Recipient acknowledges and agrees this confidentiality undertaking is intended to be for the benefit of, and enforceable by, the Company. Cautionary Statement Regarding Forward-Looking Statements This presentation includes forward looking statements. The words “expect”, “anticipate”, “intends”, “believe”, “may”, “predict”, “will”, “plan”, “estimate”, “aim”, “forecast”, “project” and similar expressions (or their negative) identify certain of these forward looking statements, although not all forward-looking statements contain these identifying words. These forward looking statements are statements regarding the Company's intentions, beliefs or current expectations concerning, among other things, the Company's results of operations, financial condition, liquidity, prospects, growth, strategies and the industry in which the Company operates. The forward looking statements in this presentation are based on numerous assumptions and estimates, believed by the Company to be reasonable at the time made, regarding the Company's present and future business strategies and the environment in which the Company will operate in the future. Forward looking statements involve inherent known and unknown risks, uncertainties and contingencies because they relate to events and depend on circumstances that may or may not occur in the future and may cause the actual results, performance or achievements of the Company to be materially different from those expressed or implied by such forward looking statements. Many of these risks and uncertainties relate to factors that are beyond the Company's ability to control or estimate precisely, such as future market conditions, currency fluctuations, the behavior of other market participants, the actions of regulators and other factors such as the Company's ability to continue to obtain financing to meet its liquidity needs, changes in the political, social and regulatory framework in which the Company operates or in economic or technological trends or conditions. Past performance should not be taken as an indication or guarantee of future results, and no representation or warranty, express or implied, is made regarding future performance. Statements contained herein describing documents and agreements are summaries only and such summaries are qualified in their entirety by reference to such documents and agreements. Each forward-looking statement in this presentation speaks only as of the date of this presentation. Except as required by applicable law, the Company disclaims any intention, obligation or responsibility to revise or update any forward-looking statements contained in this presentation to reflect events or circumstances occurring after the date of this presentation. Industry and Market Data This presentation has been prepared by the Company and includes market data and other statistical information from third-party sources, including independent industry publications, government publications or other published independent sources. Although the Company believes these third-party sources are reliable as of their respective dates, the Company has not independently verified the accuracy or completeness of this information. Some data is also based on the Company's good faith estimates, which are derived from a review of internal sources as well as the third-party sources described above. 1

Disclaimers (cont’d) Reserve Presentation This presentation includes information with respect to proved, probable and possible reserves of the Company. Under SEC rules, proved reserves are those quantities of oil and natural gas that 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, operating methods and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. Non-GAAP Financial Measures EBITDAX is a supplemental non GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. The Company defines 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 the other items described below. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP. The GAAP measure most directly comparable to EBITDAX is net income (loss). Management believes EBITDAX is useful because it allows them to more effectively evaluate the Company’s operating performance and compare the results of the Company’s operations from period to period and against the Company’s peers without regard to financing methods or capital structure. The Company excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within the Company’s industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. 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 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. The Company’s presentation of EBITDAX should not be construed as an inference that the Company’s results will be unaffected by unusual or nonrecurring items. The Company’s computations of EBITDAX may not be comparable to other similarly titled measures of other companies. PV-10 is also considered a non-GAAP financial measure. PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure and, as used in this presentation, is determined based on SEC pricing. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. The Company believes that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to its estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of its oil, natural gas liquids (“NGL”) and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of the Company’s reserves to other companies. The Company uses this measure when assessing the potential return on investment related to its oil, NGL and natural gas properties. PV-10, however, is not equal to, or a substitute for, the standardized measure of discounted future net cash flows. The Company’s PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of its oil and natural gas reserves. 2

Jones Energy – Overview Western Anadarko Basin (WAB) Merge Austin, TX [1] Reserves and PV-10 figures as of 12/31/2017 assuming NYMEX pricing as of 07/31/2018. See slide 5 for important information regarding proved, probable and possible reserves. [2] Represents operated sections/acres. [3] Sections in Merge, acreage in WAB. [4] Actual 3 months ending June 30, 2018. 3 Company HQ Asset Summary [1] Net Acres ('000s) % HBP by YE18 [2] Operated Sections / % [3] Total Sections Production (MBoed) [4] % Oil % Liquids Operated Wells Identified Locations [1] MMBoe 1P MMBoe 3P PV-10 ($mm) 1P PV-10 ($mm) 3P Merge 21.2 100% 38 201 10.3 31% 59% 45 ~2,300 28 359 $269 1,559 WAB 152.2 86% 85%+ NM 14.7 26% 57% 765 ~1,700 76 181 $475 662 Total 173.4 ~80% NM NM 25.0 28% 58% 810 ~4,000 104 540 $744 2,221

Jones Energy – Key Value Drivers Contiguous 21K+ net acres in core of Merge, including Meramec as extension from STACK and Woodford as extension from SCOOP; will be HBP by 2018YE Jones and peers have substantially delineated the play, now moving to development Potential accretive reserve enhancements as Jones and other area operators improve well-performance by optimizing spacing, completions and other techniques Significant, visible, capital-efficient growth with 500+ gross operated drilling locations with ~30%+ single-well IRRs[1] Strong WTI price realizations with mature infrastructure Base production of ~14.7 MBoed from ~1,400 wells augmented with active, low-capex, high-return, short-payback “small ball” workovers; 86% HBP, 85% operated Step-change in Core Cleveland drilling returns since the Nov. 2017 cost-neutral improvement in flowback and completions design > 50% IRR since vs. <20% 2014 – 2017 Core Cleveland growth path with 100+ identified, high value locations Strong early flowback from Malinda well in Marmaton suggests a potential new growth avenue with 20+ locations Recent TCOG success in Turkey Track generated 70%+ IRR, inclusive of midstream savings; 20+ locations Strong WTI price realizations with mature infrastructure Recent management changes made to improve capital and cost discipline as well as process-rigor and detail-focus in drilling selection and operations Enhanced 3D landing point targeting, geosteering, casing design, completion, flowback and lift protocol are improving wells DrillCo, in advanced discussions with an exclusive counterparty, will accelerate value creation in both Merge and WAB A recapitalization transaction with Unsecured Debtors would enhance the Company’s liquidity runway and option duration with d ecreased interest burden Could lead to accelerated drilling program and / or a second-step capital markets transaction to further strengthen the Company’s credit profile One of the few, if not only, potentially-available large, contiguous acreage positions in the Merge WAB would be an attractive “additional leg” to an efficient, cash-flow-oriented and moderate-growth operator [1] See page 11 for details. 4 Complementary asset fit with in-and out-of-basin operators provides potential strategic combination upside Current cash position provides multi-year runway and an effective real-option on oil prices and positive developments in the Merge and WAB Legacy WAB provides base cash flow as well as additional, lower-risk growth avenues High-return Merge play transitioning to development phase with significant de-risking / value-affirming offset activity

Jones Energy – Reserves + $10 WTI[2] PV-10 + $10 WTI[2] PV-10 + $10 WTI[2] PV-10 Reserves PV-10 Reserves PV-10 Reserves PV-10 Mmboe $mm $mm Mmboe $mm $mm Mmboe $mm $mm PDP PDNP[1] PUD 1P 3P 9 5 $101 63 $121 76 45 3 $374 8 $449 12 54 8 $476 71 $570 88 14 104 139 28 92 152 43 197 291 28 359 $269 $1,559 $335 $2,108 76 181 $475 $662 $613 $965 104 540 $744 $2,221 $948 $3,073 Note: WAB figures include minimal amount of non-WAB assets. Source: Reserve reports prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers; assumes NYMEX pricing as 07/31/2018. [1] PDNP inclusive of PDSI. [2] Impact of commodity price sensitivity is only reflected in PV-10 figures. 5 WABMerge$3,073 NYMEXNYMEX +$10 WTI $2,221 $2,108 $1,559 $965 $662 WABMerge $948 NYMEXNYMEX +$10 WTI $744 $335 $269 $613 $475 3P PV-10 ($mm) 1P PV-10 ($mm) Total WAB Merge

Merge – Overview The main target zones in the Merge are Meramec[1] and Woodford STACK Meramec SCOOP Sycamore [1] Reservoir thickness varies from 100’ to 400’ with average porosity of 4% to 10% Key Targets Woodford Gross Thickness 50’ - 500' 50' - 300' Merge offers stacked-pay with well-developed targets defined by substantial vertical well-control Net-to-Gross 30 - 40% 30 - 60% Porosity 3 - 7% 3 - 6% CANADIAN GRADY McCLAIN [1] Sycamore, or Mayes, is age equivalent to Meramec. 6 NS World Class Petroleum Systems Oil Generation/Migration Basin PLATFORM STACK Merge SCOOP Cross-Section Schematic MERGE Meramec Woodford 100’ - 400' 40 - 80% 4 - 10% Reservoir Comparison

Merge – Jones’ Acreage Position Multiple stacked drilling targets Well-developed benches in the Meramec with high porosity and permeability De-risked by substantial historical vertical production Substantial Woodford exposure with proven reservoir properties Operated acreage will be 100% HBP by YE2018 Substantial acreage in the oil window Shallower depths reduces drilling costs Strong price realizations with mature infrastructure 7 CANADIAN OKLAHOMA CLEVELAND CADDO GRADYMcCLAIN Jones Acreage Oil Gas Condensate – Low GOR Gas condensate – High GOR Wet gas

Preliminary Draft Subject to Change Merge – Active “Neighborhood” y ys ~ 25 Roan 1 Note: Rigs per Drillinginfo and Rig Data. 8 Merge activity has significantly accelerated from 3 rigs in March 2016 to ~25 rigs currentl Up 8x vs. 2x for other NAM horizontal pla Merge offers exposure to “best of both” attributes of SCOOP and STACK Competitor activity quickly de-risking and affirming value across the play JONE maintaining one rig to HBP acreage CONFIDENTIAL CANADIAN OKLAHOMA CLEVELAND CADDO GRADY McCLAIN Merge Rig Activity Other 6 Operators by Rig Count2Cam 16 JONE March '16Current ino Jones Acreage Camino ~50K net acres 2 active rigs 3 Roan ~115K net acres >200 op sections 6+ active rigs

Merge – Key Well Results 4 Bomhoff 2H Rosewood 1H Rosewood 2H Govenor James 1H Hrdy 1-11MH Bone 2H Hinparr 1XH Collins 1XH Garrett 1H Shepperd 1H JONE JONE JONE Roan MRO JONE Roan Roan JONE Travis Peak 4,428' 4,579' 4,586' 4,960' 4,935' 4,375' 9,900' 9,500' 4,697' 10,877' 1,601 1,168 1,459 2,143 2,122 1,358 2,441 3,492 1,171 1,395 34% 40% 36% 65% 49% 61% 65% 52% 53% 37% 1 2 CANADIAN 2 3 2 OKLAHOMA 1 5 4 5 8 6 6 7 8 7 3 8 4 CLEVELAND 3 9 CADDO 7 6 9 Bomhoff 1H Rosewood 3H Paxton 1H Griffin 1HX Bone 1H Meyers 1H Hines Federal 1H Dutch 1H-33-28 Larry 1H JONE JONE Roan Roan JONE XEC XEC Roan NFX 4,366' 4,382' 10,175' 6,500' 4,322' 7,982' 9,453' 9,700' 9,850' 941 865 1,774 2,476 543 2,233 2,867 1,918 1,930 25% 40% 29% 63% 65% 24% 35% 41% 82% 1 2 3 4 9 McCLAIN GRADY 5 6 7 8 9 Source: Company presentations, IHS. Production data are reported as actuals on a three-s am basis; data is not normalized for lateral length. 9 Jones Acreage Meramec Well Woodford Well JONE Well Well Name Operator Lateral Length IP30 (Boed) % Oil Woodford Wells Meramec Wells Well Name Operator Lateral Length IP30 (Boed) % Oil

Merge – Key Operational Levers Superior reservoir quality High net-to-gross Liquids rich Over pressured Shallower Structurally simple Site Identification Landing Point Targeting & Geosteering Use 3D seismic for all operated wells Hit landing point, make tight curve and stay straight and in-zone Re-establish personnel continuity, coordination and best practices Continue to work-down drill times Optimize casing design, completion and flowback Implement efficient field development plan Operations Protocol Establish best practice for artificial lift Gas lift, ESP and jet pumps used to date; jet pumps appear most effective Lift Protocol 10

Merge – Economics 150%+ 50%+ 35%+ 35%+ 30%+ 20%+ 110 1 Oil - 525 29 Low GOR - 155 8 High GOR - 390 1 Oil - 760 29 Low GOR - 375 8 High GOR - Gros s 3P Loca ti ons Opera ted Secti ons MRMC $5.5 MRMC $5.8 MRMC $6.5 WDFD $5.6 WDFD $5.9 WDFD $6.6 Single Well Gross AFE ($mm) Returns PV-10 / I nves tment Pa yout (Months ) 3.1x 12 1.6x 26 1.3x 40 2.1x 23 1.7x 29 1.7x 31 NYMEX pricing as of 07/31/2018 - 2018: $66.86 / $2.98; 2019: $64.94 / $2.74; 2020: $61.56 / $2.63. WTI +$10/Bbl pricing - 2018: $76.86 / $2.98; 2019: $74.94 / $2.74; 2020: $71.56 / $2.63. Metrics shown un-risked. Company incorporates various risk factors including weather, downtime and general forecast to generate forecast. 11 IRR 150%+ 35%+ 20%+ 50%+ 35%+ 30%+ IRR (WTI + $10/Bbl) 220%+ 55%+ 30%+ 70%+ 50%+ 40%+ PV-10 ($mm) $11.4 $3.6 $2.0 $6.4 $4.0 $4.4 PV-10 ($mm) (WTI + $10/Bbl) 14.9 5.2 3.5 8.7 5.8 6.1 Woodford Meramec

WAB – Overview 150,000+ net acres 86% HBP, 85% operated 100+ identified gross operated high return locations in Core Cleveland ~1,400 existing well-bores Substantial opportunity for low-capex, high-return, short-payback “small ball” workovers Recent Marmaton and Turkey Track successes add two further growth avenues Contiguous acreage supports pad drilling and other operational efficiencies Supportive, flexible midstream arrangements in-place 12 Jones Acreage Cleveland Play Turkey Track Area Core Cleveland Marmaton Focus Area Jones WAB Acreage

WAB – Uplift from Enhanced Cleveland Completions Implemented NextGen completion and flowback strategy in November 2017 25,000 5x 33-stage open hole design with bespoke frac plan by stage 20,000 Instituted soakback period and drill-out strategy prior to gas lift 1.15x 15,000 Since implementation, 7 Cleveland wells drilled 10,000 Significant performance uplift (1.5x) 5,000 Fewer days to peak rates Zero mechanical issues, sand at surface 0 01 301 60 90 Cost neutral Days Since First Prod NextGen process is applicable throughout Jones’ acreage [1] Revenue adjusted assumes gas valued based on price realizations instead of hydrocarbon amount. Gas stream conversion assumes denominator of 13.4 instead of 6, which assumes $3.00 / mcf residue gas, $22.00 / bbl NGL, 32% gas shrink and 0.11 bbl / mcf NGL yield. [2] Cleveland Type Curve is base underwritten curve based on NextGen Completion Strategy. 13 Cumulative Production (Boe) 16 / '17 Wells1. NextGen Well Average Cleveland Type Curve [2] NextGen Wells vs. ‘16 / ‘17 Wells – Rev. Adj. 90 Day Cum.Production [1]

WAB – Development Strategy Accelerate implementation of proven uplift protocol Likely DrillCo driven Accelerate Core Cleveland Focus on and execute high impact, low capex workovers on ~1,400 incumbent wellbores “Cleanse” uneconomic latent wells Ramp-up “Small Ball” Build on Recent Malinda Success in Marmaton Strong initial production rates; 20+ locations Potential continued XOM 50% participation per farm-out agreement mitigates capital need Most recent well with new design suggests 70%+ IRR; 20+ locations IRRs aided/de-risked by midstream savings Continue Turkey Track Granite Wash and Atoka Seismic Divest Non-Core Assets 14

WAB – Economics 1,000%+ 70%+ [2] 50%+ 45%+ 100+ 20-40 20+ NA Identi fi ed Opera ted Loca ti ons Single Well Core Cleveland [1] Marmaton $3.6 Turkey Track "Small Ball" Gross AFE ($mm) Returns $2.3 $2.7 < $0.5 1 PV-10 / Inves tment Pa yout (Months ) 1.4x 29 1.4x 24 1.6x 20 NYMEX pricing as of 07/31/2018 - 2018: $66.86 / $2.98; 2019: $64.94 / $2.74; 2020: $61.56 / $2.63. WTI +$10/Bbl pricing - 2018: $76.86 / $2.98; 2019: $74.94 / $2.74; 2020: $71.56 / $2.63. Metrics shown un-risked. Company incorporates various risk factors including weather, downtime and general forecast to generate forecast. [1] Represents uplift from NextGen Enhanced Completion Strategy. See page 13 for detail. [2] Inclusive of midstream savings. 15 IRR45%+50%+70%+ IRR (WTI + $10/Bbl)65%+80%+90%+ PV-10 ($mm)$0.9$1.5$1.5 PV-10 ($mm) (WTI + $10/Bbl)1.42.52.3 20%+

Business Plan – Summary Merge Demonstrate efficacy of enhanced 3D-targeting, geostreering, casing design, completion technique, flowback and lift protocol HBP operated acreage by YE18 WAB With DrillCo, accelerate PUD conversion in Core Cleveland Build on nascent Marmaton success to demonstrate new 20+ well growth path Similarly, build on the solid results from the improved D&C process in the Turkey Track; 20+ locations Focus-on and implement high-return, low-capex “small ball” across the ~1,400 incumbent wellbores Close DrillCo to accelerate value in WAB and HBP’ing of Merge Near final close with exclusive counterparty Will leverage the increased drilling volume to drive organizational redevelopment / 3-rig activity Diligently manage costs LOE and G&A Monitor capital markets Look for opportunity to follow-up a potential Unsecured partial equitization to achieve greater de-leveraging and financial flexibility Actively pursue value-accretive alternatives with potential strategic partners 16

Business Plan – Investment Assumes DrillCo development plan through Q1 2020 (25 Merge wells, 40 WAB wells) Merge Development Ri gs 1.6 1.6 3.0 3.0 3.0 We l l s / Ri g / Mo n th 0.9 1.1 1.4 1.4 1.4 Gross Wells 17 20 51 52 52 Wtd . Avg. Wo rki n g I n te re s t 69% 63% 65% 65% 65% Net Wells Ave ra ge AFE Oth e r 12 $7.6 0.6 13 $6.2 0.1 33 $5.9 0.2 34 $6.0 – 34 $6.0 – 3 operated Merge rigs thereafter Net Drilling Capital Ca rry-I n / (Ou t) Sp on s or Dri l l Co. $88.6 19.7 (7.2) $77.7 (12.1) (46.2) $197.6 (9.4) (24.1) $201.9 – – $201.9 – – Drilling spread evenly across WDFD & MRMC Low GOR & High GOR type curve areas WAB Development Ri gs 0.7 2.1 0.3 0.3 0.3 We l l s / Ri g / Mo n th 1.6 1.5 1.0 1.0 1.0 Gross Wells 13 37 4 4 4 Wtd . Avg. Wo rki n g I n te re s t 82% 80% 78% 78% 78% Net Wells Ave ra ge AFE Oth e r 10 $2.3 0.3 30 $2.4 0.7 3 $3.1 0.7 3 $3.0 0.7 3 $3.0 0.7 4 WAB wells / year 2019+ in addition to DrillCo wells Net Drilling Capital Ca rry-I n / (Ou t) Sp on s or Dri l l Co. $24.8 0.7 (8.8) $73.4 (4.1) (43.9) $10.3 3.6 (2.9) $10.0 0.2 (0.1) $9.9 0.2 – Op e ra te d De ve l op me n t Non -Op De ve l op me n t $117.7 17.6 $44.8 22.6 $175.2 16.9 $212.0 16.7 $212.0 16.7 Mt. Ca p e x / Pool i n g / Le a s i n g 20.8 10.0 8.4 8.4 7.9 17 Total Capital Expenditures $156.1 $77.5 $200.5 $237.0 $236.5 Total Development Capital $135.3 $67.5 $192.1 $228.7 $228.6 Total WAB Operated $16.6 $25.4 $11.1 $10.2 $10.1 Total Merge Operated $101.1 $19.4 $164.1 $201.9 $201.9 Capex Summary ($ in millions) 2018E 2019E 2020E 2021E 2022E

Business Plan – Financial Projections Reflects latest type curves for Merge and WAB, accounting for forecast risk, downtime and weather risk Wells Spud Me rge - JONE WAB - JONE Me rge Dri l l Co. 27 42 – 14 6 3 1 4 19 48 4 3 52 4 – 52 4 – WAB D ri l l Co . – 7 33 – – – Total Operated Wells Spud Production Oi l (MBbl ) Ga s (MMcf) 69 30 57 55 56 56 1,964 20,424 2,260 19,840 1,778 17,180 2,055 18,793 2,901 25,966 3,460 32,446 NGL (MBo e ) 2,418 2,367 2,127 2,348 3,217 4,034 Total Production (MBoe) Daily Production (MBoe/d) Growth % (QoQ) / (YoY) Financial Projections 7,786 21.3 10.7% 7,933 21.7 1.9% 6,768 18.5 (14.7%) 7,536 20.6 11.3% 10,445 28.6 38.6% 12,901 35.3 23.5% $183.7 $231.7 $185.3 $195.5 $266.1 $321.1 Commodi ty Re ve nue He d ge Re ve n u e / Oth e r 69.4 (49.4) (19.5) (5.6) 2.8 2.8 $253.1 (36.6) (6.9) (21.3) $182.3 (42.2) (13.8) (29.1) $165.8 (38.0) (11.3) (23.4) $189.9 (39.7) (11.9) (23.4) $268.9 (51.4) (16.3) (23.4) $323.9 (60.4) (19.3) (23.4) Total Revenue LOE Prod. Ta x / Ad . Va l . / Tra ns . G&A Ca pi ta l Expe ndi ture s e xc. A&D Cha nge i n WC / Othe r (187.2) 8.8 (156.1) (11.7) (77.5) 2.9 (200.5) (3.0) (237.0) 1.5 (236.5) 1.1 Note: NYMEX pricing as of 07/31/2018. 18 Unlevered Free Cash Flow$9.8($70.5)$18.4($88.6)($57.8)($14.7) Cumulative$9.8($60.7)($42.3)($130.9)($188.7)($203.3) EBITDAX$188.2$97.2$93.0$114.9$177.7$220.7 EBITDAX (+$10/Bbl WTI)$188.2$96.6$100.1$137.5$224.3$286.2 JONE Projections ($ in millions) 2017A 2018E 2019E 2020E 2021E 2022E

Business Plan – Merge Type Curves 200,000 Lateral Length 5,000 10,000 180,000 IP30 Oil (Bbl/d) Gas (MMcf/d) NGL (Bbl/d) Boe/d 160,000 415 1,655 1,075 3,130 140,000 195 290 120,000 886 1,887 100,000 EUR Mix Oil Liquids 80,000 25% 56% 31% 56% 60,000 40,000 D&C ($mm) $5.8 $8.5 20,000 – – 30 60 90 120 150 180 Days on Production Source: Peer Company Presentation Materials provided to the Public. [1] Industry production figures per Peer Company Presentation Materials provided to the public. JONE production figures based on Low GOR Meramec Type Curve (most operated sections and locations). Production presented on two-stream basis using 20:1 Bbl / MMcf conversion. [2] Returns based on flat price deck of $65 / Bbl Oil and $2.75 / Mcf Gas prices. 19 Cumulative Production (Boe) JONEIndustry Industry – 10,000’ Lateral JONE – 5,000’ Lateral IRR35%+100%+ Type Curve Overview [1][2] JONE Industry Relative Production Comparison [1]

Business Plan – Forecast Sensitivities $93.0 $100.1 $107.2 $99.3 $107.3 $115.4 $105.5 $114.5 $123.6 114.9 137.5 161.5 128.9 153.9 182.8 142.9 172.4 209.9 177.7 224.3 282.6 209.5 277.9 343.2 254.4 330.1 392.9 220.7 286.2 339.1 275.2 335.3 395.5 317.0 384.4 451.8 Note: Natural gas pricing held constant at NYMEX pricing as of 07/31/2018. 20 EBITDAX 2019E 2020E 2021E 2022E Base TC +30% NYMEX Strip Price for Oil as of 7/31/2018 +$0 +$10 +$20 Base TC +15% NYMEX Strip Price for Oil as of 7/31/2018 +$0 +$10 +$20 Base TC NYMEX Strip Price for Oil as of 7/31/2018 +$0 +$10 +$20

APPENDIX

Tax Matters – TRA Early Termination Payment $58.7 million Projected Early Termination Payment (“ETP”) as of June 30, 2018 Discounted future payments based on exchanges that have occurred to date and hypothetical exchange of remaining 9.1 million Class B shares $58.4 million as of 12/31/2017, following tax reform $105.1 million as of 9/30/2017, before tax reform ETP has reduced variability following 2017 exchanges Future change in magnitude due primarily to the movement of the remaining 9.1 million Class B shares Driven by share price and tax basis of the remaining Class B shares $50.5 million GAAP balance sheet liability as of June 30, 2018 Undiscounted future payments based on exchanges that have occurred to date Gross liability, reduced by reserve for tax benefit that will not be realized (under GAAP accounting for income taxes) TRA Payments $1.6 million payment during Q1 2018 for the 2016 tax year Do not anticipate payment for 2017 or 2018 tax years Change in base assumption due to liability management and/or DrillCo could lead to TRA payment 22

CONFIDENTIAL SUBJECT TO CONFIDENTIALITY AGREEMENTS, FRE 408, AND STATE LAW EQUIVALENTS Proposal to Ad-Hoc Group of Senior Noteholders August 2, 2018 $222mm of new 6.0% 2L debt D&O tail insurance THIS TERM SHEET IS FOR DISCUSSION PURPOSES ONLY. THIS TERM SHEET DOES NOT PURPORT TO SUMMARIZE ALL OF THE TERMS, CONDITIONS, REPRESENTATIONS, WARRANTIES, AND OTHER PROVISIONS WITH RESPECT TO THE TRANSACTIONS DESCRIBED HEREIN, WHICH TRANSACTIONS WILL BE SUBJECT TO THE COMPLETION OF DEFINITIVE DOCUMENTS INCORPORATING THE TERMS SET FORTH HEREIN AND THE CLOSING OF ANY TRANSACTION SHALL BE SUBJECT TO THE TERMS AND CONDITIONS SET FORTH IN SUCH DEFINITIVE DOCUMENTS. NO BINDING OBLIGATIONS WILL BE CREATED BY THIS TERM SHEET UNLESS AND UNTIL BINDING DEFINITIVE DOCUMENTS ARE EXECUTED AND DELIVERED BY ALL APPLICABLE PARTIES. 1 CLIENT LOGO Max height=0.46" Revolver No modification Treatment of Claims Hedges No modification 1L Notes No modification Unsecured Notes Exchanging Noteholders receive: 32% of fully-diluted common equity TRA No modification Pref. Equity Receive TBD% of fully-diluted common equity Common Equity Diluted to TBD% ownership Minimum Participation 95% of Unsecured Noteholders Other Other Key Terms Comprehensive mutual releases Management compensation program

Proposal to Jones Energy By Steering Committee of SUNs September 17, 2018 Introduction Key Terms Set forth at right are the key terms of an exchange transaction supported by the Steering Committee of senior unsecured notes (“SUNs”) of Jones Energy 1 RBL Refinanced or amended to provide at least $50mm borrowing capacity SUN SteerCo willing to backstop as a delayed-draw term loan Hedges No modification 1L Notes No modification Participating SUNs $275mm of new 2L Convertible PIK Notes (the “2L Notes”) 13% PIK Interest Convertible at holder’s option at [•]% premium to equity value 90% pro forma common equity (pre-dilution from the 2L Notes, Warrant Package and MIP equity) Participating SUNs will accept accrued interest payable on the date of the exchange transaction in the form of incremental 2L Notes TRA To be reconciled via mutually agreeable transaction Series A Preferred [•]% pro forma common equity (pre-dilution from the 2L Notes, Warrant Package and MIP equity) [•]% of Warrant Package (see below) Existing Common [•]% pro forma common equity (pre-dilution from 2L Notes, Warrant Package and MIP equity) [•]% of Warrant Package (see below) Warrant Package Warrants for 10% of the common equity (pre-dilution from MIP equity; not diluted by 2L Notes) Strike price equal to a Participating SUN recovery of (i) par plus (ii) accrued interest through the date of the exchange transaction 4 year tenor Other Key Terms Transactions to be consummated out of court MIP to be negotiated with current management Participating SUNs will consent to amendments to existing SUN indentures providing for elimination / modification of certain covenants New board will be appointed by SUN SteerCo; existing directors to provide consent to new board members