Exhibit 99.2

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Results Driven. Manufacturing Focused. Management Presentation July 2019 www.sanchezenergycorp.com

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Legal Disclaimers This Presentation is being provided to potential investors to assist them in their investigation of Sanchez Energy Corporation in accordance with procedures established by us and Moelis & Company LLC (“Moelis”). This Presentation does not purport to contain all of the information that may be required to evaluate all of the factors that would be relevant to a recipient considering entering into any transaction with us and any recipient hereof should conduct its own investigation and analysis. The distribution and use by each recipient of the information contained herein and any other information provided to the recipient by us or Moelis is governed by a confidentiality agreement, a copy of which has been executed and delivered by each recipient and which strictly limits the circulation and copying of the information contained in this Presentation. IF YOU HAVE NOT EXECUTED AND DELIVERED SUCH A CONFIDENTIALITY AGREEMENT, YOU HAVE RECEIVED THIS PRESENTATION IN ERROR. IF SO, PLEASE NOTIFY US OR MOELIS IMMEDIATELY AND RETURN THIS PRESENTATION TO US. Except as provided in such confidentiality agreement, this Presentation may not be distributed, reproduced or used without our express consent or for any purpose other than the evaluation of a potential transaction (as described in such confidentiality agreement) by the person to whom this Presentation has been provided. The business plan and other materials set forth or referenced herein have been prepared to facilitate discussions with certain of the Company’s stakeholders regarding a potential financial restructuring transaction and do not reflect a formal budget or work plan approved by the Board of Directors; accordingly, such materials should be considered illustrative in draft form subject to material change, and the Company does not undertake the obligation or intend to provide public updates to these materials. Forward-Looking Statements. This presentation contains “forward looking statements” within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward looking statements. These statements are based on certain assumptions we made based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this presentation, words such as “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “forecast,” “budget,” “guidance,” “project,” “profile,” “model,” “strategy,” “future” or their negatives or the statements that include these words or other words that convey the uncertainty of future events or outcomes, are intended to identify forward looking statements, although not all forward looking statements contain such identifying words. In particular, statements, express or implied, concerning our future operating results and returns or our ability to replace or increase reserves, increase production, or generate income or cash flows, service our debt and other obligations and repay or otherwise refinance such obligations when due or at maturity, operational and commercial benefits of our partnerships, expected benefits from acquisitions, including the transactions we closed in the first quarter of 2017 (the “Comanche Acquisition”) whereby we, along with an entity controlled by The Blackstone Group, L.P. (“Blackstone”), Gavilan Resources, LLC (“Gavilan”), acquired assets from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (“Anadarko”), and our strategic relationship with Sanchez Midstream Partners LP (“SNMP”) are forward looking statements. Forward looking statements are not guarantees of performance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. Although we believe that the expectations reflected in our forward looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Important factors that could cause our actual results to differ materially from the expectations reflected in the forward looking statements include, among others: the timing and extent of changes in prices of, and demand for, crude oil and condensate, natural gas liquids (“NGLs”), natural gas and related commodities; our ability to successfully execute our business and financial strategies; our ability to comply with the financial and other covenants in our debt instruments, to repay our debt, and to address our liquidity needs, particularly if oil and natural gas prices remain volatile and/or depressed; the extent to which we are able to engage in successful strategic alternatives to improve our balance sheet and satisfy our obligations under our debt instruments; the extent to which we are able to pursue drilling plans and acquisitions that are successful in maintaining and economically developing our acreage, producing and replacing reserves and achieving anticipated production levels; our ability to successfully integrate our various acquired assets into our operations and realize the benefits of those acquisitions to fully identify existing and potential issues or liabilities and to accurately estimate reserves, production and costs with respect to such assets; our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure, debt service and other funding requirements through internally generated cash flows, asset sales and other activities; the extent to which our listing on an over-the-counter securities exchange rather than a national securities exchange will impair our access to equity markets and ability to obtain financing; our ability to utilize the services, personnel and other assets of Sanchez Oil & Gas Corporation (“SOG”) pursuant to an existing services agreement; SOG’s ability to retain personnel and other resources to perform its obligations under that services agreement; the realized benefits of our partnerships and joint ventures, including our transactions with SNMP and our partnership with affiliates of Blackstone; the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise; the effectiveness of our internal control over financial reporting; the extent to which we can optimize reserve recovery and economically develop our properties utilizing horizontal and vertical drilling, advanced completion technologies, hydraulic stimulation and other techniques; the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities; our ability to successfully execute our hedging strategy and the resulting realized prices therefrom; the availability, creditworthiness and performance of our counterparties, including financial institutions, operating partners and other parties; the extent to which requests for credit assurances, or minimum volume commitments or “take-or-pay” obligations in excess of our oil and natural gas deliveries to, or transportation needs from, our contractual counterparties could have a material adverse effect on our business, financial condition and results of operations; competition in the oil and natural gas exploration and production industry generally and with respect to the marketing of crude oil, natural gas and NGLs, acquisition of leases and properties, attraction and retention of employees and other personnel, procurement of equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services; the extent to which our production, revenue and cash flow from operating activities are concentrated in a single geographic area; developments in oil producing and natural gas producing countries, the actions of the Organization of Petroleum Exporting Countries and other factors affecting the supply and pricing of oil and natural gas; the extent to which third-party operators operate our crude oil and natural gas properties successfully and economically; our ability to manage the financial risks where we share with more than one party the costs of drilling, equipping, completing and operating wells, including with respect to the assets acquired in the Comanche Acquisition (“Comanche Assets”); the use of competing energy sources, the development of alternative energy sources and potential economic implications and other effects therefrom; results of litigation filed against us or other legal proceedings or out-of-court contractual disputes to which we are party; the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage, including losses related to sabotage, terrorism or other malicious intentional acts (including cyber-attacks) that disrupt operations; the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws, regulations, restrictions and guidelines with respect to derivatives, hedging activities and commercial lending standards; and the other factors described under “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018 and any updates to those factors set forth in our subsequent Quarterly Reports on Form 10-Q or Current Reports on Form 8-K. In light of these risks, uncertainties and assumptions, the events anticipated by our forward-looking statements may not occur, and, if any of such events do, we may not have correctly anticipated the timing of their occurrence or the extent of their impact on our actual results. Accordingly, you should not place any undue reliance on any of our forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake 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. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. Oil and Gas Reserves. The Securities and Exchange Commission (“SEC”) requires oil and gas companies, in their filings with the SEC, to disclose “proved oil and gas reserves” (i.e., quantities of oil and gas that are estimated with reasonable certainty to be economically producible) and permits oil and gas companies to disclose “probable reserves” (i.e., quantities of oil and gas that are as likely as not to be recovered) and “possible reserves” (i.e., additional quantities of oil and gas that might be recovered, but with a lower probability than probable reserves). We may use certain terms in this presentation, such as “resource potential” or “EURs” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The calculation of resource potential, EURs and any other estimates of reserves and resources that are not proved, probable or possible reserves are not necessarily calculated in accordance with SEC guidelines. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018. Non-GAAP Measures. Included in this presentation are certain non-GAAP financial measures as defined under SEC Regulation G. Investors are urged to consider closely the disclosure in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K and any reconciliation to GAAP measures provided in this presentation. 2

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Management Representatives Tony Sanchez, III President and Chief Executive Officer Cam George Executive Vice President and Chief Financial Officer Greg Kopel Executive Vice President, General Counsel and Secretary 3

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Agenda I. II. III. IV. V. Executive Summary Asset Overview Management Track Record Proposed Business Plan Projections and Financial Highlights Appendices: A. B. C. Consolidated and UnSub Financial Projections Corporate G&A Overview Commodity Market Backdrop and Summary Capitalization 4

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION I. Executive Summary 5

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Company History Strong Track Record of Organic and Transactional Growth 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 2011 2012 2013 2014 2015 2016 2017 2018 2011 2014 2016 2017 2018 6 Boe/d Completed ~$2.3 billion Comanche acquisition: 155,000 acres, 67 MBoe/d and 300 MMBoe in proved reserves (with partner) Acquired Catarina from Shell; Doubled proved reserves Capital budget reached $250 MM Achieved production of ~79 MBoe/d; Surpassed $1 billion in revenues Completed IPO at ~600 Boe/d

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Organizational Structure Services Agreement 100% ommon Units 100% Sanchez Resources, LLC 100% 100% 100% 100% Senior Notes due 2021 Partners LP (“SNMP”) UnSub, LP GP interest Units) % hereafter Unrestricted Subsidiary Credit Agreement & Senior Notes) (1) As of 6/10/19. (2) GSO ST Holdings Associates LLC owns the Class B Unit in SN EF UnSub GP, LLC, which holds the GP interest in SN EF UnSub, LP. GSO ST Holdings LP owns 485,000 preferred units in SN EF UnSub, LP, and the remaining 15,000 preferred units in SN EF UnSub, LP are held by Intrepid Private Equity Fund I, LP and Intrepid Private Equity SPV-A, L.P. 7 Sanchez Oil & Gas Corporation (“SOG”) Other Sanchez Group Public Sanchez Energy Corporation (“SN”) Issuer SN UR Holdings, LLC SN Capital, LLC SN Palmetto, LLC C SR TMS, LLC 100% 2,272,727 SN Debt / Preferred Equity SN Marquis LLC SR Acquisition III, LLC 100% $25 MM first-out senior secured working capital and letter of credit facility SN Cotulla Assets, LLC SR Acquisition I, LLC SN Services, LLC $500 MM of 7.25% Senior Secured Notes due 2023 SN Operating, LLC 100% SN Terminal, LLC100% $24 MM$4.25 MM non-recoursesecured non-credit facilityterm loanSN Midstream, LLC100% SN Comanche Manager, LLC100% 100%SN EF UnSub recourse 4.59% $600 MM of 7.75% SN TMS, LLC 100% $1.15 B of 6.125% Senior Notes due 2023 SN Catarina, LLC 100% Sanchez Midstream $39.0 MM of 4.875% Series A Preferred Stock $125.6 MM of 6.500% Series B Preferred Stock Rockin L Ranch Company, LLC 100% 100% Holdings, LLC 100% common SN EF 100% SN EF UnSub GP, LLC 99% SN EF Maverick, LLC 100% (99 Class A non-economic 100%1 B Unit) 60%100% of of development40% o Unrestricted Subsidiarypost-acquisitiont acquisition PDP & f development preferred (1 Class Restricted Subsidiary (Guarantor of SN Credit Agreement & Senior Notes) $500 MM non-recourse revolving credit facility Comanche Assets (SN’s Net ~25% WI) GSO Capital Partners LP(2) Restricted Subsidiary (Guarantor of SN SN Payables, LLC

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Asset Ownership ~12.5% Note: Percentages shown represent interest in future development. 8 Sanchez Energy Corporation Gavilan (Blackstone) ~25% KNOC ~25% Venado (KKR) ~12.5% Mitsui Restricted Comanche ~15% UnSub Comanche ~10% Catarina 100% Maverick 100% Palmetto ~50% Comanche

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Situation Overview 9 We have achieved tremendous growth through both organic development, as well as significant acquisition activity, and assembled a world-class asset in the Eagle Ford Shale  Much of the transactional growth occurred in a higher commodity price environment The commodity price downturn has caused us to re-evaluate our business strategy  We have refocused the business plan to prioritize free cash flow generation over production growth through improved capital efficiency and significant operational and cost initiatives We are seeking to proactively address our capital structure and liquidity constraints  The oil / liquids price downturn in recent months has prompted us to enter into discussions with our stakeholders on a comprehensive recapitalization solution  While we could pursue near-term liquidity-enhancing transactions to extend our runway, this strategy may not offer our stakeholders the same opportunity to fully participate in a commodity price recovery or enable our team to best optimize our large asset base New capital is required to maximize the value of our assets  Meaningful new investment will be necessary to enable the continued realization of significant benefits from the recent performance enhancement program we have executed We have developed a high-graded business plan that offers asset stability and future free cash flow generation, with significant margin expansion from a commodity price recovery  We have prepared a comprehensive business plan that incorporates the operational improvements, cost reduction efforts and other initiatives underway with the goal of creating a sustainable enterprise capable of consistently delivering free cash flow to stakeholders

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Key Takeaways 10 Strategic, Highly Concentrated Eagle Ford Shale Position  Dominant position of ~485,000 gross (~283,000 net) acres in the Eagle Ford Shale  ~77% of our net acreage is held by production and continuous drilling obligations  Integrated two major acquisitions (Catarina from Shell, and Comanche from Anadarko) which transformed the Company into one of the largest and most active operators in the basin Decades of Lower Risk, Repeatable Drilling Inventory  2,000+ identified drilling locations in the development plan based on optimal well spacing  Future upside from multiple benches in the Eagle Ford with 4,000+ potential drilling locations and additional opportunities from the Austin Chalk and Pearsall Shale Recognized Low Cost Operator  Historically recognized as one of the lowest cost operators in the Eagle Ford  Rapidly improving cost structure through comprehensive and rigorous performance review  Recently reduced corporate headcount by 20%-30% and achieved meaningful cost savings Strong Management Track Record of Asset Optimization  Management identified Catarina as an underperforming property with significant upside and quickly implemented a development program that optimized it into a crown jewel asset  Conducted similar program at Comanche with positive and promising trajectory Recent Operational Initiatives Already Producing Results  Optimized completions, flowback strategy and spacing at Comanche in 2018  Initiated aggressive frac interference mitigation program, coupled with workover and artificial lift enhancement, to maximize base PDP well performance  Targeting lowest risk, highest return potential benches and retaining “science” benches in long-term inventory for future upside opportunities

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION II. Asset Overview 11

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Core Asset Overview Sanchez Energy holds one of the largest contiguous acreage positions across any U.S. producing basin (1) Price deck referenced in year-end 2018 Ryder Scott SEC reserve report was $65.56 WTI and $3.10 Henry Hub. 12 Comanche  Acquired from Anadarko (2017)  Gross acres: ~318,000  Net acres: ~77,500  Total engineered Eagle Ford locations: ~845  Total identified Eagle Ford locations: ~2,795  Proved reserves: ~141 MMBoe  SEC(1) PV-10: ~$1.0 billion  Current production: ~28 MBoe/d Comanche Catarina Catarina Acquired from Shell (2014)  Gross acres: ~106,000  Net acres: ~106,000  Total engineered Eagle Ford locations: ~510  Total identified Eagle Ford locations: ~595  Proved reserves: ~220 MMBoe  SEC(1) PV-10: ~$1.3 billion  Current production: ~36 MBoe/d

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Strategically Concentrated Acreage Position Large, concentrated asset base drives significant synergies of scale Cost savings from moving rigs and equipment  Shared resources for in-field gathering, water transportation, etc. More efficient drilling process   Substantial asset-level knowledge applied to neighboring acreage  More efficient field-level operations  Enhanced pricing from volume and location  13 Maverick Comanche Catarina Core Acreage Position Within a ~40 Mile Radius Provides Unique Competitive Advantages

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Stable Production Base Across 2,400+ Wells Sanchez Energy produces from a broad base of more than 2,400 wells across its asset portfolio(1) Managing the business for a more stable production base reduces future maintenance capital requirements and helps position the Company for free cash flow and margin expansion in a higher commodity price environment Estimated 3-year base decline rate from 2020-2023 is less than 15%    90 -16% -13% -13% 80 70 60 50 40 30 20 10 0 2019 2020 2021 2022 2023 (1) Well count shown represents the estimated number of total wells across the portfolio, including any wells which may be offline from time to time, including for service, workover activities or in connection with comprehensive frac mitigation strategies. (2) Reflects Consolidated production from year-end 2018 Ryder Scott SEC reserve report. Excludes all future development. 14 MBoe/d -33% -21% Estimated PDP Production Profile(2)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Well-Defined Geology with Repeatable Development Potential Maverick Maverick Comanche Comanche Catarina Catarina 150’ 0’ 350’ 175’ 0’ 255’ Upper Eagle Ford is prominent throughout most of Catarina The Upper Eagle Ford fairway also extends into select areas of Comanche Lower Eagle Ford is prominent throughout most of Comanche The Lower Eagle Ford is the most proven and consistent zone throughout the entire play   15 Lower Eagle Ford Thickness Upper Eagle Ford Thickness

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Multi-Year Inventory of Organic Growth Opportunities Commitment (1) As of 6/11/19. Well count shown specifically represents the estimated number of producing wells online as of that date and excludes wells across the portfolio which were offline, including for service, workover activities or in connection with comprehensive frac mitigation strategies. (2) At current assessment of optimized well spacing and targeting, net to Restricted Group. (3) Total identified Eagle Ford locations, net to Restricted Group. Excludes potential opportunities associated with other prospective horizons, including the Austin Chalk and Pearsall Shale. 16 Area Net Production(1) (MBoe/d) % Oil(1) Producing Wells(1) Est. Total Engineered Eagle Ford Locations(2) Est. Total Identified Eagle Ford Locations(3) Gross Well Per Year Catarina ~36 25% 414 ~510 ~595 50 Comanche 28 37% 1,666 845 (125 net) 2,795 (420 net) 48 - 60 Maverick 3 97% 66 790 790 ~3 Palmetto 2 74% 88 80 (40 net) 230 (115 net) ~10 Total ~69 35% 2,234 ~2,225 (~1,465 net) ~4,410 (~1,920 net) ~111 - 123 Comanche Catarina Maverick Palmetto

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION III. Management Track Record 17

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Catarina Case Study Strong Track Record of Value-Added Asset Optimization Acquired from Shell in 2014 Shortly after closing, oil prices plummeted from $100+ to ~$50 per Bbl However, we added significant value through capital investment and aggressive cost management Rapidly doubled production within the first year Divested midstream assets for ~$350 million in 2015 Significant upside inventory remains for commodity price recovery Historical Cash Flow Asset Value  Purchase Price Cumulative Cashflow Catarina Midstream Transaction ($639) ($189) $345 PDP PUD Total Proved $729 $605 $1,334  Total ($483) Money Multiple Money Multiple on PDP 2.8x 1.5x  60 $120 50 $100 40 $80  30 $60 20 $40  10 $20  0 $0 Note: Reserve values from year-end 2018 Ryder Scott SEC reserve report. 18 Oil Price ($) Catarina Production (Mboe/d) Jul-14 Oct-14 Ja n-15 Apr-15 Jul-15 Oct-15 Ja n-16 Apr-16 Jul-16 Oct-16 Ja n-17 Apr-17 Aug-17 Nov-17 Feb-18 Ma y-18 Aug-18 Nov-18 Feb-19 Production Oil Price Management has demonstrated the ability to create substantial value and generate attractive returns, even in a declining commodity price environment

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Catarina Case Study Demonstrated Ability to Rapidly Address Operational Challenges Trial activity yielded unfavorable results  - - Tested large completion designs, tight well spacing and aggressive flowback strategies Results were unfavorable, with performance ~20% below type curves 60,000 55,000 50,000 45,000 Management took decisive action  - - 40,000 Adjusted rig schedule to prioritize highest return areas Shifted well spacing and completion design away from testing and into development with prudent, data-driven approach Strong and clear results: production has increased ~40% off the lows in Q2 2017 35,000 30,000 25,000 - 20,000 15,000 Current production has remained strong and responded well to low cost, low risk optimization projects begun in late 2018  10,000 19 Large completions testing with negative results Quickly implemented corrective actions in the field Prioritized inventory and executed optimized completion design, well spacing and flowback strategy with almost immediate results Nimble and experienced management team has proven highly effective in quickly addressing operational issues with strong and clear results

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Lessons Learned and Proactive Operational Leadership 1. Upper Eagle Ford Well Performance Based on proven success at Catarina Large step-out test driven by JDA partner Disappointing Upper Eagle Ford performance in the A and C benches in appraisal pads outside of the fairway Sanchez significantly reduced capital to the Upper Eagle Ford program and will non-consent any additional wells driven by partner outside of the fairway     2. Testing of Aggressive Flowback Strategy Attempted to improve NPV and accelerate cash flow timing Successfully tested in areas with higher oil yields and better pressure Testing of various choke management strategies in late 2017 and early 2018 negatively impacted performance Sanchez determined conservative flowback strategy to be superior from IRR, EUR and NPV perspectives based on tests and is committed to executing strategy going forward     3. Completion Designs Successful results from many industry leaders with significantly larger completions designs Tested a variety of completion designs in 2017 to determine optimal completions for Comanche (similar to post-acquisition Catarina growth strategy) Lower cost full slickwater design with ~1,700-2,000 lbs/ft demonstrating strong results Testing phase helped determine optimal go-forward design     4. Acquired DUC Spacing Too Tight Even with observed underperformance, the economics were still attractive based on low cost of completing the drilled but uncompleted (“DUC”) wells Previous operator had spaced DUCs at ~450 ft. (132 wells at acquisition) Aggressive infill program drove spacing even tighter, leading to the underperformance Entire acquired DUC inventory has cycled through development program New wells will not be spaced closer than ~450 ft. where appropriate      5. Managing PDP Downtime (Frac Hit and Workovers) Development schedule required significant new development activity near offset PDP wells Experienced an increase in downtime and lost production Began active workover program to stabilize PDP decline Adjusted 2019 development plan to reduce frac interference     6. Right-Sizing G&A Post Comanche Integration Demonstrated efficient operator based on Catarina successes Implementing our proven strategies at Comanche Comanche was a transformative acquisition that quickly multiplied the size of the Company Recently reduced workforce by ~20%-30% Continue to evaluate and take action on additional cost-cutting measures throughout organization      20 InitiativeOriginal RationaleOutcomeResponse Implemented

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Focusing Upper Eagle Ford Activity in the Fairway Testing was driven by widespread success at Catarina and the potential to add material location counts and asset NAV Step-out appraisal testing continued under the Joint Development Agreement despite poor initial results Fairway delineation is based on correlation of reservoir quality and pressure to actual production data Sanchez does not plan to participate in Upper Eagle Ford tests outside of the fairway going forward ~130 Upper Eagle Ford engineered locations based on the delineated fairway      21 Normalized Cumulative BOE Normalized Cumulative BOE Normalized Cumulative BOE Normalized Cumulative BOE INSIDE FAIRWAY UEF Cumulative BOE 97% of LEF TC BOE days INSIDE FAIRWAY UEF Cumulative BOE 99% of LEF TC BOE days OUTSIDE FAIRWAY UEF Cumulative BOE 69% of LEF TC BOE days OUTSIDE FAIRWAY UEF Cumulative BOE 46% of LEF TC BOE days Completed Appraisal Activity to Define Upper Eagle Ford Fairway

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Returning to Conservative Flowback Standard Choke Avg. Aggressive Choke Avg. Results do not support continued implementation of aggressive choke strategies across the asset base  100,000 90,000 Oil decline on an aggressive choke strategy steepens after ~50 days, resulting in less revenue than the standard choke strategy  80,000 70,000 Previous operator used a more conservative choke strategy, which targeted significantly reduced drawdown in comparison to aggressive testing  60,000 50,000 40,000 Recent pivot back to a more conservative choke strategy has shown improved results  30,000 20,000 Based on positive results, we believe managing drawdowns on reservoir pressure is the most beneficial flowback strategy  10,000 0 Production Day 22 Cumulative Oil Production 1 20 39 58 77 96 115 134 153 172 191 210 229 248 267 286 305 ~50 Days Tested Flowback Strategies to Accelerate NPV

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Testing Completion Design and Well Spacing Strategies Appropriate completion design at appropriate well spacing is critically important Comanche is a geologically complex asset that requires individual development strategies 80,000  70,000 60,000 We now have the data to analyze the optimal combination of completion size and well spacing  50,000 40,000 The graph depicts several recent wells from the Briscoe Metcalf and Briscoe Catarina North pads, which were completed with 2,000-2,600 lbs/ft and 50-60 bbls/ft  30,000 20,000 10,000 Early results show success when applying this completion design with the appropriate well spacing  0 Production Day 23 Cumulative Oil Production 1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103 109 115 121 Briscoe Met 1HZ (UEF) Briscoe Met 1HY Briscoe Met 2HY Briscoe CatN 110H Briscoe CatN 116H Briscoe CatN 112H Briscoe Met 1HS Type Curve Extensively Tested Completion Designs Since Comanche Acquisition

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Focusing on Frac Mitigation to Protect Existing Production CPF Downtime 27% Frac interference contributed to nearly half of the PDP underperformance  Frac Interference 48% We have established a more extensive shut-in program when completing offset wells  Artificial Lift Issues 11% Midstream Downtime 14% Testing frac interference mitigation techniques across our asset base with promising results  Future development plan has been designed to limit drilling near high value production  New wells planned with minimum 1,000 ft. spacing from PDP wells  24 Buffer Map Mitiga tion Candidate Child Well 1,000’ Buffer 2,000’ Buffer Implementing Highly Promising Frac Mitigation Strategy

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Prioritizing Workover and Artificial Lift Program 400 ~80 Wells Targeted 350 Reduce lift point and EOT by ~800 ft. TVD Reduce operating costs Reduce failure frequency  300  Western Freeze 250  200 150 ~60 Wells Targeted 100 Reduce lift point and EOT by ~800 ft. TVD Focus on wells where plunger is not the optimal lift method Reduce swabbing and have steadier production  50  0 5/1/2017 7/1/2017 9/1/2017 11/1/2017 1/1/2018 3/1/2018 5/1/2018 7/1/2018 9/1/2018 11/1/2018 1/1/2019  Gas Oil 2,500 400 350 300 250 200 150 100 50 0 ~270 Wells Targeted 2,000 Reduce EOT by ~800 ft. TVD Lower orifice valve to have deeper point of injection Significantly increases chance that well will be lifting at the deepest point post-kickoff, as casing pressure drops and well unloads  1,500  1,000  500 0 25 Bbls/d Well Count Mcf/d (60) (55) (50) (45) (40) (35) (30) (25) (20) (15) (10) (5) 0 5 10 15 20 25 30 35 40 45 50 55 60 Gas Lift Redesign Attractive Gas Lift Redesign Results Plunger to Gas Lift Flooding Flooding Frac Activity Begins Offline Well Count is Trending Down Well Uptime Continues to Improve Rod Pump to Gas Lift

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Aggressive Cost Management Drives Value Sanchez has been recognized as one of the lowest cost operators in the Eagle Ford During the commodity downturn, we earned a strong reputation by achieving industry-leading drilling and completion costs We are once again focused on generating value through safe, low cost operations Rigorous negotiations with service providers De-bundled approach when contracting for drilling and completion services Optimized processes and designs to ensure more efficient field operations       20% 18% 16% 14% 12% 10% 8% 6% 4% 2% 0% $0.00 $0.25 Well Cost Savings ($MM) $0.50 26 IRR (%) Delta Relentless Focus on Driving Value Through Efficient Operations

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Clear Path to Achieving G&A Target We have already reduced our corporate overhead costs by nearly 30% from 2018 levels (~$29 MM) Management has identified an additional ~$20 MM in savings that are being actively pursued   $MMs $120 $100 $80 $60 $40 $20 $0 Note: Figures shown on a consolidated basis. (1) Excludes one-time employee severance payments. (2) Excludes incremental costs associated with executive and employee incentive/retention programs for 2019. 27 $20 $7 $14 $8 $104 $55 $75 $97 Management has already made substantial progress toward achieving our long-term G&A target

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Actively Right-Sizing the Organization and Cost Structure Cumulative management efforts to-date have reduced employee headcount to pre-Comanche levels, while the Company retains full benefit of production and cash flow from the acquired properties We are committed to further streamlining our cost structure to best position Sanchez for the future   350 300 250 200 150 100 50 0 2014 2015 2016 2017 2018 Current Note: Headcount illustration represents all employees of SOG for the periods shown. 28 Employee Headcount Comanche319320 Acquisition 255 ~25% Reduction 248 218212

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION IV. Proposed Business Plan 29

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Core Objectives Minimize external funding needs while still growing production  Create path toward positive free cash flow at current commodity prices  Continue to aggressively reduce corporate overhead costs  Offer attractive investment opportunity with significant upside exposure to oil prices  Retain and enhance core competencies and competitive advantages  Maintain operational and financial resilience through future commodity cycles  30 Sanchez Energy is committed to developing and implementing a sustainable business model that meets the following core planning objectives:

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Unique Asset Base Provides High Degree of Capital Flexibility Note: Reinvestment Ratio defined as capital / EBITDA. Strip pricing sourced from Bloomberg as of 6/27/19. Cases shown are illustrative, on a consolidated basis, and have been prepared using certain key assumptions. 31 Path 2: Maximize Production Growth 201920202021202220235-Year Total Avg. Production (MBoe/d) Capital ($MM) EBITDA ($MM) EBITDA less Capital ($MM) Reinvestment Ratio Production Profile with Annual Development Wedges (Boe/d) 130,000 110,000 90,000 70,000 50,000 30,000 10,000 1/1/20191/1/20201/1/20211/1/20221/1/2023 PDP20192020202120222023 $262 $278 $423 $472 $511 $1,947 $152 ($286) ($142) ($86) ($55) ($417) 42% 203% 134% 118% 111% 121% 91.0 $2,363 64.9 73.3 95.5 108.5 112.8 $110 $564 $566 $558 $566 Path 1: Maximize Cash Flow 201920202021202220235-Year Total Avg. Production (MBoe/d) Capital ($MM) EBITDA ($MM) EBITDA less Capital ($MM) Reinvestment Ratio Production Profile with Annual Development Wedges (Boe/d) 130,000 110,000 90,000 70,000 50,000 30,000 10,000 1/1/20191/1/20201/1/20211/1/20221/1/2023 PDP20192020202120222023 $262 $263 $302 $334 $346 $1,508 $152 ($53) ($9) $22 $48 $159 42% 120% 103% 94% 86% 89% 69.4 $1,348 64.9 63.2 68.8 72.7 77.3 $110 $317 $311 $313 $299

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Reinvestment Ratio Analysis – Oil Price Sensitivities Path 1: Maximize Cash Flow Efficient business plan drives significant potential margin expansion with modest price recovery   Production (MBoe/d) 64.9 63.2 68.8 72.7 77.3 69.4 Capital ($MM) $110 $317 $311 $313 $299 $1,348 Note: Figures shown on a consolidated basis. (1) Reinvestment Ratio defined as capital / EBITDA. (2) Assumes gas price of $2.75/MMBtu and NGL (Mt. Belvieu propane) price of $24.00/Bbl. 32 EBITDA$253$227$265$298$306 $50EBITDA less Capital$143($89)($46)($15)$8 Reinvestment Ratio43%139%117%105%97% $1,349 $1 100% EBITDA$273$287$341$380$389 $60EBITDA less Capital$163($30)$30$67$90 Reinvestment Ratio40%110%91%82%77% $1,669 $321 81% EBITDA$293$346$416$461$471 $70EBITDA less Capital$184$30$105$149$173 Reinvestment Ratio37%91%75%68%63% $1,989 $641 68% EBITDA$314$406$492$543$554 $80EBITDA less Capital$204$89$181$231$255 Reinvestment Ratio35%78%63%58%54% $2,309 $960 58% 201920202021202220235-Year

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION V. Projections and Financial Highlights 33

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Business Plan Assumptions (SN Consolidated) Note: Strip pricing sourced from Bloomberg as of 6/27/19. (1) SN Catarina and Comanche marketed NGL product components have averaged approximately 53% ethane, 26% propane, 15% butanes and 6% pentane in recent months under current plant environments. Basket components may change depending upon future gas quality, plant operations and recovery strategies. (2) Includes water transfer via SNMP at Catarina. 34 $MM $ / Boe $60 $55 $55 $55 WTI Oil ($/Bbl) $59.33 $57.10 $54.88 $54.16 $54.22 Pricing (As of 6/27/19) Base Case - Strip20192020202120222023 Henry Hub Gas ($/MMBtu)$2.37$2.55$2.60$2.63$2.70 Commodity Price Realizations  Differentials have been developed by asset area based on historical 12-month average as compared to current futures pricing. Realizations Catarina Comanche Maverick Palmetto OBO SR TMS Oil (% WTI) 101% 99% 105% 102% 104% 106% 103% Gas (% Henry Hub) 103% 104% 101% 102% 62% - - NGL (% WTI) (1)24%25%27%27%27%--Lease Operating Expense LOE(2) Mark eting Deficiencies $0.90 $1.03 $0.60 $0.45 $0.37 2019 2020 2021 2022 2023 G&A $70 20192020202120222023 $8.43 $8.42 $8.37 $8.27 $8.33 $3.06 $3.12 $3.16 $3.29 $3.53 $11.76 $11.84 $12.13 $12.73 $12.86

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Business Plan Assumptions (SN Consolidated) 35 # gross wells Drilling Activity CatarinaComancheOther 20192020202120222023 Gross Wells43108125118125 Net (Restricted)1753666565 Net (UnSub)36667 10 10 10 64 65 57 10 59 51 50 51 1 30 39 12 43 108 118 125 125

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Business Plan Assumptions (SN Consolidated) Catarina(2) Comanche (Gen 16) Maverick Palmetto (1) Assumed long-term well costs based on 2018 average well cost adjusted for 2019 average development lateral length. 2018 average vs. 2019 projected lateral lengths: Catarina (~7,500 ft. vs. ~5,800 ft.), Comanche (~7,800 ft. vs. ~5,800 ft.) and Maverick (~10,200 ft. vs. ~5,700 ft.). (2) AFE-based pricing of ~$4.1 million per well in Q1 2020+; ~$4.4 million for remainder of FY 2019. (3) AFE-based pricing of ~$3.8 million per well in Q3 2020+; ~$4.5 million for remainder of FY 2019. 36 $MM $MM Capital Expenditures CatarinaComancheOther 20192020202120222023 % D&C73%94%94%94%94% Long-Term Well Costs(1) Drilling Completions Facilities, Lift & Flowback (3) $3.6 $2.1 $2.4 $1.8 $2.0 $1.7 $1.5 $1.1 $3.8 $4.1 $4.1 $5.9 $18 $56 $36 $33 $57 $227 $33 $59 $218 $33 $56 $223 $33 $66 $200 $110 $299 $313 $311 $317

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Illustrative Marketing Diagrams and Cost Overview 2019 2020+ Contract 5 2019 2020+ (2) 2019 2020+ Note: Oil rates should be applied to net oil volumes. Gas rates should be applied to net dry gas volumes. (1) Interruptible contracts and rates which can change upon notification from counterparty. (2) Adjusted annually based on a cost of service model to achieve a certain rate of return. * Denotes contracts that SNMP is a party to directly or through a joint venture. 37 Sales NGL Purchase Oil Stabilization Stabilization/NGL Purchase NGL Transport Oil Transportation Transportation Gas Processing Wellhead Gathering 3% 4% 97% 96% Contract 3 (2) Contract 19 Contract 20 Oil (~$4.35/Bbl) Comanche Contract 13 Contract 8* Contract 4* Contract 14 Contract 9 Contract 1 Contract 15 Contract 2 (2) Contract 5 Contract 10 Contract 16 Contract 6 Contract 11 Contract 17 20192020+ Contract 7 Contract 12 Contract 18 4% 32% 3% 33% 64% 64% Gas (~$4.34/Mcf) 64% 64% 36% 36% Contract 2* (1) Contract 8 Contract 12 Contract 13 Oil (~$3.85/Bbl) 47% 47% 53% 53% Contract 1* (1) Contract 3* Contract 6* Contract 9 Contract 4 Contract 7 Contract 10 Contract 11 Gas (~$3.43/Mcf) Catarina

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Reconciliation of YE 2018 SEC Proved Reserves to 3P Management Case We have prepared a 3P database which reflects the key assumptions presented in the proposed business plan The below illustration describes the material reconciling items between this internally prepared 3P database and the Company’s third-party year-end 2018 SEC reserve report (Restricted Group only)   The estimated adjustments and 3P value shown may not be indicative of amounts which could be derived using other key assumptions, such as a different pace of capital activity or higher or lower commodity prices  $2,500 $57 $2,000 $1,500 $1,000 $500 $0 PDP Development Increase Decrease Note: This illustrative waterfall was prepared according to a specific sequence which is important to understand. (1) The material inputs (e.g., price and expense profile) from the YE 2018 Ryder Scott SEC reserve report were incorporated into the 3P management case database, which reflects the key assumptions presented herein regarding the proposed business plan. (2) Individually and on a cumulative basis, adjustments were made for each of the categories shown in the illustration in the following order: (a) application of a 2% production risking based on estimated frac interference and downtime assumptions, (b) adjustment for the effective date of the database, from YE 2018 to the present date, (c) LOE and expense profile changes based on recent trends, (d) increase in realized and estimated marketing rates during YTD 2019, (e) updated well cost assumptions by asset, and (f) the reduction in commodity prices from YE 2018 SEC pricing to the current strip (reference prices shown above). (3) Technical PUDs (locations which would reasonably meet the requirements for SEC PUDs other than 5-year development timing) and estimated probable locations were removed, as by definition they are not included in a 1P reserve report. (4) The difference between the resulting value and the YE 2018 Ryder Scott SEC reserve report is reflected in the illustration under the adjustment category “Development and Other” and is intended to reflect timing and other cumulative adjustments, such as updates to commodity price differentials and variations in individual location selection between the two databases. 38 PV-10 ($ MM) $336 $1,908 $856 $42 $188 $1,124 $1,052 $1,233 $143 $6 $26 $451 $673 Strip Pricing (6/27/19) Oil Nat. Gas Year ($/Bbl) ($/MMBtu) 2019 $59.33 $2.37 2020 $57.10 $2.55 2021 $54.88 $2.60 2022 $54.16 $2.63 2023 $54.22 $2.70 YE 2018 SEC Pricing (Flat) Oil Nat. Gas NGLs ($/Bbl) ($/MMBtu) ($/Bbl) $65.56 $3.10 $37.58

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Reserve Summary (Restricted Group) Reserve and PV10 Summary ($ in millions) Reserve and PV10 Summary ($ in millions) PDP 28 212 37 100 $489 PDP 32 243 42 115 $673 PDSI 0 1 0 0 (1) PDSI --2 --1 4 PUD 59 347 61 177 146 Development 252 727 132 506 446 Total Proved 86 560 98 277 $634 Total Proved 285 972 175 622 $1,124 (1) Represents year-end 2018 Ryder Scott 1P reserve report for restricted subsidiaries using an effective date of 1/1/19 and strip pricing as of 6/27/19. (2) Management case for restricted subsidiaries using an effective date of 4/1/19 and strip pricing as of 6/27/19. 39 Reserve Category Reserves Oil Gas NGL Equiv. PV-10 MMBbls Bcf MMBbls MMBoe $MM Reserve Category Reserves Oil Gas NGL Equiv. PV-10 MMBbls Bcf MMBbls MMBoe $MM 3P Management Case (2) Year-End 2018 Ryder Scott 1P Report (1)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Illustrative Asset-Level Type Curve Parameters Type curve parameters represent average for asset   Weighted average of IPs and initial declines based on wells drilled within specific type curve areas in the first 5 years Assets generally assume B-Factor of 1.2  Gas parameters shown net of volume shrinkage  Note: Illustrative well assumptions: (a) 100% working interest and 75% net royalty interest, (b) wells drilled in June, completed in July and first production in August through the end of economic life, and (c) strip pricing as of 6/27/19. 40 PALMETTO Oil IP (Bbls/d) Initial Decline (%) Oil EUR (MBbls) 708 80% 298 Gas IP (Mcf/d) Initial Decline (%) Gas EUR (MMcf) 940 83% 338 NGL NGL Yield (Bbl/MMcf) NGL EUR (MBbls) 133 45 3-Stream EUR (MBoe) 399 % Oil 75% COMANCHE Oil IP (Bbls/d) Initial Decline (%) Oil EUR (MBbls) 377 78% 200 Gas IP (Mcf/d) Initial Decline (%) Gas EUR (MMcf) 870 60% 879 NGL NGL Yield (Bbl/MMcf) NGL EUR (MBbls) 148 130 3-Stream EUR (MBoe) 476 % Oil 42% CATARINA Oil IP (Bbls/d) Initial Decline (%) Oil EUR (MBbls) 372 81% 165 Gas IP (Mcf/d) Initial Decline (%) Gas EUR (MMcf) 2,729 70% 1,934 NGL NGL Yield (Bbl/MMcf) NGL EUR (MBbls) 133 258 3-Stream EUR (MBoe) 745 % Oil 22%

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Representative Type Curve Parameters by Area Below are illustrative parameters for certain of the major type curve areas by asset that represent the majority of future development value in the 3P Management Case  Type curves were constructed using the averages of all completed wells that met appropriate parameters, such as completion designs and lateral lengths that are reflected in future development plans for each area  Coma nche BD_AREA_3_1_4729 BD_AREA_3_1C_4619 BD_AREA_3_3_5638 BD_AREA_5_7_5700 685 222 831 493 32% NM 36% 57% 350 380 350 425 1.2 1.2 1.2 1.0 70 88 69 66 950 950 1,250 350 1.2 1.2 1.2 0.9 50 80 50 41 147.8 147.8 147.8 147.8 Ca ta ri na BD_CATNC_6009 BD_CATSC_UEFC_6034 BD_CATWSO_5915 724 1,178 603 24% 43% 16% 370 450 380 1.2 1.2 1.2 77 80 81 1,699 3,900 1,995 1.2 1.2 1.2 60 67 70 133.2 133.2 133.2 Ma veri ck BD_Ma veri ck_Ba s e 221 21% 430 1.2 79 1 1.2 30 107.5 Pa l metto BD_BHS_RS2_5000 490 NM 1,100 1.2 89 1,840 1.2 87 133.1 Note: Illustrative well assumptions: (a) 100% working interest and 75% net royalty interest, (b) wells drilled in June, completed in July and first production in August through the end of economic life, and (c) strip pricing as of 6/27/19. 41 Type Curve Area EUR (MBoe) IRR Oil-IP Oil B-Factor Oil-Di Gas-IP Gas B-Factor Gas-Di NGL/Gas

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Catarina Completion Design Previous operator tested variations of conventional designs  Lower fluid and proppant volumes  "Ball and sleeve" applications 2014 tests of modern completion designs  Varied volume intensities  "Plug and perf" application 2015 testing informed current standard design  ~30 Bbls/ft of fluid and ~1,700 lbs/ft of proppant 2015-2018 tests of high intensity designs were successful in single well applications, but failed to meet expectations in development setting     42 Completion Timing Completion Designs – Fluid Volumes Completion Designs – Evolution Completion Designs – Proppant Volumes

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Comanche Completion Design 2019 Planned Wells 2017-2018: Tested higher intensity designs ~50+ Bbls/ft and ~2,000+ lbs/ft on ~300’ well spacing Modified and conservative choke strategies Prior operator design ~30 Bbls/ft and ~800 lbs/ft with ~500+ well spacing 2017: Tested the Catarina design with a modified choke strategy ~30 Bbls/ft and ~1,700 lbs/ft with ~300’ well spacing 2018-2019: Delineating successful higher intensity designs ~50 Bbls/ft and ~2,000 lbs/ft on ~450’+ well spacing Monitored drawdown strategies 43 Completion Design Evolution

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Sanchez Energy Corporation Restricted Subsidiaries and its (“Restricted Group”) 44

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Financial Highlights: Base Case (6/27/19 Strip Pricing) Restricted Group 44.0 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 Note: Detailed financial forecast provided on page 46. 45 $292 $277 $242 $195 $177 $90 $20 ($99) ($46) ($13) Unlevered Free Cash Flow ($MM) Adjusted EBITDAX ($MM) $294 $287 $290 $272 $86 62.5 57.0 52.1 45.2 Production (MBoe/d) Capital Expenditures ($MM)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Projections: Base Case (6/27/19 Strip Pricing) Restricted Group ($ in thousands) (1) Reflects estimated Consolidated G&A less an assumed allocation to UnSub of approximately $7.5 million for 2019 and $5 million per year thereafter, based on certain historical trends and future expectations. Actual G&A allocation between Restricted Group and UnSub may be more or less than the amounts shown, with such allocation determined in accordance with the applicable contract. 46 1Q 19 2Q 19 3Q 19 4Q 19 2019 1Q 20 2Q 20 3Q 20 4Q 20 2020 2021 2022 2023 Net Production: Comanche Restricted (Boe/d)7,9336,5295,8115,930 Non-Comanche Restriced (Boe/d)45,49938,56834,71031,085 6,544 37,419 5,4344,9235,3435,499 31,12937,75946,83543,604 5,300 39,861 5,716 46,358 6,192 50,856 6,342 56,159 Total Net Production (Boe/d)53,43245,09840,52237,016 43,962 36,56342,68252,17849,103 45,162 52,074 57,048 62,501 Commodity Price: Oil ($/Bbl)$54.90$61.38$59.45$59.17 Gas ($/MMBtu)$3.15$2.56$2.32$2.45 NGL ($/Bbl)$27.82$23.66$21.54$23.96 Realized Price: Oil ($/Bbl)$54.63$62.09$60.17$59.87 Gas ($/Mcf)$3.30$2.64$2.38$2.52 NGL ($/Bbl)$17.44$13.41$12.16$13.54 Oil Revenue$87,114$82,706$72,363$64,608 Gas Revenue$31,014$21,349$17,565$17,079 NGL Revenue$28,732$19,093$15,782$16,192 $58.73 $2.62 $24.24 $58.90 $2.75 $14.34 $306,792 $87,008 $79,799 $58.36$57.43$56.61$55.99 $2.67$2.42$2.49$2.61 $24.64$23.54$24.27$25.62 $59.01$57.99$57.12$56.54 $2.75$2.50$2.56$2.69 $13.92$13.31$13.71$14.49 $61,442$72,207$89,511$85,468 $18,348$19,254$24,264$23,623 $16,345$18,007$22,720$22,342 $57.10 $2.55 $24.52 $57.52 $2.62 $13.87 $308,628 $85,488 $79,413 $54.88 $2.60 $25.63 $55.33 $2.67 $14.50 $336,895 $101,028 $96,043 $54.16 $2.63 $25.81 $54.60 $2.70 $14.58 $372,884 $110,473 $104,587 $54.22 $2.70 $25.52 $54.66 $2.77 $14.43 $382,260 $128,279 $117,003 Oil, Gas, & NGL Revenue$146,861$123,149$105,710$97,878 $473,598 $96,134$109,468$136,495$131,432 $473,529 $533,966 $587,944 $627,543 Hedge Gain / (Loss) $1,740 ($3,281) ($2,160) ($2,302) LOE$12,100$11,530$11,407$11,114 Marketing$39,209$32,549$29,449$27,213 Deficiencies$0$4,807$6,444$7,619 Total Operating Expenses$51,308$48,886$47,301$45,946 Production Taxes$6,052$4,997$4,315$3,973 Ad Valorem Taxes$3,098$2,515$2,164$2,005 Cash G&A(1)$19,329$17,324$13,125$13,125 ($6,003) $46,152 $128,419 $18,870 $193,441 $19,337 $9,783 $62,903 $0$0$0$0 $10,608$10,836$11,474$12,198 $26,721$31,088$38,398$35,379 $7,631$5,343$2,048$3,664 $44,960$47,267$51,920$51,241 $3,862$4,432$5,508$5,309 $1,958$2,200$2,723$2,644 $13,750$13,750$13,750$13,750 $0 $45,115 $131,587 $18,686 $195,388 $19,110 $9,526 $55,000 $0 $49,244 $152,090 $8,866 $210,200 $21,408 $10,683 $50,000 $0 $53,550 $165,404 $6,762 $225,717 $23,566 $11,750 $50,000 $0 $57,699 $184,031 $6,313 $248,043 $24,896 $12,532 $50,000 Adjusted EBITDAX$63,532$46,146$36,645$30,527 $176,850 $31,605$41,818$62,594$58,488 $194,505 $241,674 $276,912 $292,072 Total Capex$12,753$23,240$19,500$30,966 $86,458 $73,897$124,941$56,745$38,396 $293,979 $287,186 $290,045 $272,333 Unlevered Free Cash Flow$50,779$22,906$17,145($438) $90,392 ($42,293)($83,123)$5,849$20,093 ($99,475) ($45,512) ($13,133) $19,739

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Projections: 13 Week Cash Flow Forecast Restricted Group Sanchez Energy Corp1 13 Week Cash Flow Total Week En d in g : Total Forecast ($ in 0 0 0 s) Cash & Cash Equi val ents - Begi nni ng Cas h Recei p ts Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Forecast Wk 1 - 1 3 $ 1 8 5 ,0 7 9 $ 9 8 ,2 1 8 $ 9 9 ,4 7 3 $ 9 7 ,7 7 8 $ 1 7 7 ,3 8 6 $ 8 3 ,8 7 8 $ 9 5 ,2 4 8 $ 6 5 ,2 1 6 $ 1 3 1 ,1 3 2 $ 7 5 ,5 3 3 $ 8 2 ,9 7 3 $ 7 1 ,4 8 7 $ 1 7 0 ,8 5 3 $ 1 8 5 ,0 7 9 Gross P roducti on Recei pts Cash Cal l s & JIB Recei pts Hedge Settl em ents O ther 4 ,4 7 3 - - 1 0 - 1 5 ,4 7 5 3 4 0 8 6 2 1 ,9 5 7 2 1 ,4 7 3 - - 1 4 2 ,2 8 6 3 ,0 8 4 - - 7 7 7 3 ,6 3 8 - 6 - 2 8 ,3 6 8 3 5 1 8 3 - 3 ,6 3 0 - - 1 1 7 ,4 3 3 - - - 4 2 ,3 0 8 3 ,6 3 0 - - 3 8 7 2 7 ,8 1 3 3 4 7 6 - 4 0 0 - 8 3 1 1 3 ,8 4 4 3 ,6 2 3 - - 4 3 ,6 0 2 - - - 4 8 7 ,0 6 8 1 1 1 ,1 3 3 1 ,0 3 8 2 7 4 Total Cash Recei pts $ 4 ,4 8 3 $ 1 5 ,9 0 0 $ 4 3 ,4 3 0 $ 1 4 5 ,3 7 0 $ 4 ,4 2 2 $ 2 8 ,8 0 2 $ 3 ,6 3 0 $ 1 1 7 ,4 3 3 $ 4 5 ,9 3 8 $ 2 8 ,5 5 4 $ 4 8 3 $ 1 1 7 ,4 6 7 $ 4 3 ,6 0 2 $ 5 9 9 ,5 1 2 Cas h Di sb u rsem en ts Capex Lease O perati ng Expense Gatheri ng / Fi rm Transportati on Gas P urchases Di sbursem ents Hedge Settl em ents Royalties & Worki ng Interest P aym ents P roducti on & Ad Val orem Tax G&A / O ther (4 ,5 6 1 ) (3 ,1 9 2 ) (1 1 ,3 6 4 ) - - (7 1 ,9 2 3 ) - (1 5 0 ) (4 ,5 6 1 ) (3 ,1 9 2 ) (1 ,0 2 0 ) - (4 1 3 ) - - (5 ,4 5 8 ) (4 ,5 8 6 ) (3 ,1 9 2 ) (8 1 1 ) - - (7 7 8 ) - (5 4 0 ) (4 ,5 6 1 ) (3 ,1 9 2 ) (1 0 ,4 5 7 ) (2 ,0 0 0 ) - (3 5 ,9 3 7 ) (7 ,4 2 0 ) (2 ,1 9 5 ) (4 ,5 6 1 ) (3 ,1 9 2 ) (2 4 6 ) - - (8 6 ,6 3 7 ) - (3 ,1 5 0 ) (7 ,4 2 7 ) (3 ,9 6 6 ) (5 ,4 6 1 ) - (4 2 7 ) - - (1 5 0 ) (7 ,4 2 7 ) (3 ,9 6 6 ) (1 ,2 5 4 ) - - (7 4 0 ) - (2 ,1 5 0 ) (7 ,4 2 7 ) (3 ,9 6 6 ) (5 ,5 5 3 ) - - (2 7 ,6 6 6 ) (6 ,3 6 5 ) (5 4 0 ) (7 ,4 2 7 ) (3 ,9 6 6 ) (5 ,8 3 6 ) (2 ,0 0 0 ) - (7 9 ,9 9 7 ) - (2 ,1 9 5 ) (5 ,6 8 2 ) (3 ,1 5 8 ) (5 ,3 6 7 ) - (4 4 4 ) (6 ,3 1 2 ) - (1 5 0 ) (5 ,6 8 2 ) (3 ,1 5 8 ) (9 8 0 ) - - - - (2 ,1 5 0 ) (5 ,6 8 2 ) (3 ,1 5 8 ) (1 ,8 3 6 ) - - (7 1 9 ) (6 ,1 6 6 ) (5 4 0 ) (5 ,6 8 2 ) (3 ,1 5 8 ) (1 0 ,3 8 0 ) (2 ,0 0 0 ) - (2 8 ,3 0 9 ) - (2 ,1 9 5 ) (7 5 ,2 6 5 ) (4 4 ,4 5 7 ) (6 0 ,5 6 6 ) (6 ,0 0 0 ) (1 ,2 8 4 ) (3 3 9 ,0 1 8 ) (1 9 ,9 5 0 ) (2 1 ,5 6 3 ) O perati ng Cash Di sbursem ents $ (9 1 ,1 9 0 ) $ (1 4 ,6 4 4 ) $ (9 ,9 0 6 ) $ (6 5 ,7 6 2 ) $ (9 7 ,7 8 6 ) $ (1 7 ,4 3 1 ) $ (1 5 ,5 3 7 ) $ (5 1 ,5 1 7 ) $ (1 0 1 ,4 2 2 ) $ (2 1 ,1 1 4 ) $ (1 1 ,9 6 9 ) $ (1 8 ,1 0 0 ) $ (5 1 ,7 2 4 ) $ (5 6 8 ,1 0 3 ) Total O perati ng Cash Fl ow $ (8 6 ,7 0 7 ) $ 1 ,2 5 5 $ 3 3 ,5 2 4 $ 7 9 ,6 0 9 $ (9 3 ,3 6 5 ) $ 1 1 ,3 7 1 $ (1 1 ,9 0 8 ) $ 6 5 ,9 1 7 $ (5 5 ,4 8 4 ) $ 7 ,4 4 0 $ (1 1 ,4 8 7 ) $ 9 9 ,3 6 7 $ (8 ,1 2 2 ) $ 3 1 ,4 1 0 Fi n an ci n g Rel ated Cas h Fl o ws Debt Servi ce P aym ents (1 5 5 ) - (3 5 ,2 1 9 ) - (1 4 4 ) - (1 8 ,1 2 5 ) - (1 1 5 ) - - - - (5 3 ,7 5 7 ) Net Cash Fl ow P ri or to DIP Fi nanci ng $ (8 6 ,8 6 2 ) $ 1 ,2 5 5 $ (1 ,6 9 5 ) $ 7 9 ,6 0 9 $ (9 3 ,5 0 8 ) $ 1 1 ,3 7 1 $ (3 0 ,0 3 3 ) $ 6 5 ,9 1 7 $ (5 5 ,5 9 9 ) $ 7 ,4 4 0 $ (1 1 ,4 8 7 ) $ 9 9 ,3 6 7 $ (8 ,1 2 2 ) $ (2 2 ,3 4 8 ) Endi ng O perati ng Cash Bal ance $ 9 8 ,2 1 8 $ 9 9 ,4 7 3 $ 9 7 ,7 7 8 $ 1 7 7 ,3 8 6 $ 8 3 ,8 7 8 $ 9 5 ,2 4 8 $ 6 5 ,2 1 6 $ 1 3 1 ,1 3 2 $ 7 5 ,5 3 3 $ 8 2 ,9 7 3 $ 7 1 ,4 8 7 $ 1 7 0 ,8 5 3 $ 1 6 2 ,7 3 2 $ 1 6 2 ,7 3 2 Mem o : Cas h Excl u d i n g SNEFM O perati ng Cash SN EF Maveri ck Cash Bal ance $ 9 8 ,2 1 8 1 5 ,3 2 1 $ 9 9 ,4 7 3 1 3 ,2 3 4 $ 9 7 ,7 7 8 2 8 ,8 1 6 $ 1 7 7 ,3 8 6 1 1 4 ,7 4 4 $ 8 3 ,8 7 8 2 5 ,8 5 7 $ 9 5 ,2 4 8 3 8 ,9 5 2 $ 6 5 ,2 1 6 3 1 ,9 1 6 $ 1 3 1 ,1 3 2 8 7 ,1 1 3 $ 7 5 ,5 3 3 2 9 ,7 3 3 $ 8 2 ,9 7 3 3 8 ,3 7 0 $ 7 1 ,4 8 7 2 9 ,8 9 4 $ 1 7 0 ,8 5 3 1 0 8 ,7 2 1 $ 1 6 2 ,7 3 2 1 0 9 ,3 4 5 $ 1 6 2 ,7 3 2 1 0 9 ,3 4 5 O perati ng Cash l ess SN EF Maveri ck $ 8 2 ,8 9 7 $ 8 6 ,2 3 9 $ 6 8 ,9 6 2 $ 6 2 ,6 4 3 $ 5 8 ,0 2 1 $ 5 6 ,2 9 6 $ 3 3 ,2 9 9 $ 4 4 ,0 1 9 $ 4 5 ,8 0 0 $ 4 4 ,6 0 3 $ 4 1 ,5 9 3 $ 6 2 ,1 3 3 $ 5 3 ,3 8 7 $ 5 3 ,3 8 7 1 Exclu d es Ca sh of SN EF Un Su b , LP No te: SN UR Hold in g s, LLC, SN EF Un Su b , LP a n d SN EF Ma verick, LLC h a d ca sh b a la n ces of $ 6 3 .5 million , $ 18 .4 million a nd $ 7 6.1 million , resp ectively a s of 3 / 3 1 / 1 9 a nd p roj ected to b e $ 6 3 .2 million , $ 1 7 .7 million a n d $1 0 4 .3 million , resp ectively a s o f 6 / 3 0 / 1 9 47 Jul 5 ' 1 9 Jul 1 2 ' 1 9 Jul 1 9 ' 1 9 Jul 2 6 ' 1 9 Aug 2 ' 1 9 Aug 9 ' 1 9 Aug 1 6 ' 1 9 Aug 2 3 ' 1 9 Aug 3 0 ' 1 9 Sep 6 ' 1 9 Sep 1 3 ' 1 9 Sep 2 0 ' 1 9 Sep 2 7 ' 1 9 1 2 3 4 5 6 7 8 9 1 0 1 1 1 2 1 3

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Key Takeaways Proven management team with a strong track record of creating value and driving growth  Unique asset base with large, contiguous acreage position and extensive future inventory  Focused on generating value through efficient cost management  Actively managing production decline rates to provide greater asset stability  Business plan demonstrates operational flexibility to maximize free cash flow  Opportunity for significant margin expansion from a modest commodity price recovery  48

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Appendices 49

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION A. Consolidated and UnSub Financial Projections 50

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Sanchez Energy Corporation and its Consolidated (“Consolidated”) Subsidiaries 51

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Financial Highlights: Base Case (6/27/19 Strip Pricing) Consolidated 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 Note: Detailed financial forecast provided on page 53. (1) Figures represent Restricted Group unlevered cash flow combined with UnSub levered cash flow (including interest on bank debt and preferred dividends). 52 $93 ($113) ($69) ($40) ($15) $346 $334 $302 $262 $263 Free Cash Flow ($MM) (1) Adjusted EBITDAX ($MM) 77.3 72.7 68.8 64.9 63.2 $317 $311 $313 $299 $110 Production (MBoe/d) Capital Expenditures ($MM)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Projections: Base Case (6/27/19 Strip Pricing) Consolidated ($ in thousands) (1) Reflects an assumed allocation to UnSub of approximately $7.5 million for 2019 and $5 million per year thereafter, based on certain historical trends and future expectations. Actual G&A allocation between Restricted Group and UnSub may be more or less than the amounts shown, with such allocation determined in accordance with the applicable contract. 53 1Q 19 2Q 19 3Q 19 4Q 19 2019 1Q 20 2Q 20 3Q 20 4Q 20 2020 2021 2022 2023 Net Production: Comanche (Boe/d)30,77027,87625,90925,529 Non-Comanche (Boe/d)45,49938,56834,71031,085 27,502 37,419 24,35723,00723,08022,900 31,12937,75946,83543,604 23,334 39,861 22,393 46,358 21,892 50,856 21,109 56,159 Total Net Production (Boe/d)76,26866,44460,62056,615 64,921 55,48660,76669,91666,504 63,195 68,750 72,748 77,267 Commodity Price: Oil ($/Bbl)$54.90$61.38$59.45$59.17 Gas ($/MMBtu)$3.15$2.56$2.32$2.45 NGL ($/Bbl)$27.82$23.66$21.54$23.96 Realized Price: Oil ($/Bbl)$54.81$61.71$59.77$59.45 Gas ($/Mcf)$3.27$2.65$2.39$2.53 NGL ($/Bbl)$17.34$13.37$12.14$13.50 Oil Revenue$128,028$120,780$107,051$98,292 Gas Revenue$43,049$31,029$25,938$25,704 NGL Revenue$40,500$28,554$24,008$25,114 $58.73 $2.62 $24.24 $58.70 $2.74 $14.22 $454,151 $125,719 $118,177 $58.36$57.43$56.61$55.99 $2.67$2.42$2.49$2.61 $24.64$23.54$24.27$25.62 $58.62$57.68$56.87$56.28 $2.76$2.50$2.57$2.70 $13.89$13.27$13.69$14.46 $92,963$101,575$119,001$114,086 $27,378$27,111$32,172$31,752 $25,137$26,067$30,858$30,769 $57.10 $2.55 $24.52 $57.27 $2.63 $13.83 $427,626 $118,413 $112,831 $54.88 $2.60 $25.63 $55.11 $2.68 $14.47 $443,912 $131,792 $128,052 $54.16 $2.63 $25.81 $54.40 $2.71 $14.56 $474,213 $139,426 $134,658 $54.22 $2.70 $25.52 $54.48 $2.78 $14.41 $478,566 $156,107 $144,831 Oil, Gas, & NGL Revenue$211,577$180,362$156,997$149,110 $698,046 $145,478$154,754$182,032$176,607 $658,870 $703,756 $748,297 $779,503 Hedge Gain / (Loss) $218 ($5,965) ($3,337) ($3,632) LOE$22,638$20,555$20,417$20,039 Marketing$56,567$51,038$47,098$44,422 Deficiencies$0$5,664$7,571$8,788 Total Operating Expenses$79,206$77,256$75,086$73,249 Production Taxes$8,283$7,136$6,244$5,883 Ad Valorem Taxes$4,767$3,837$3,348$3,189 Cash G&A(1)$21,250$19,199$15,000$15,000 ($12,716) $83,649 $199,125 $22,023 $304,798 $27,547 $15,141 $70,448 ($1,497)($3)$1,205($1,013) $18,420$18,629$19,162$19,825 $43,183$46,857$53,928$50,614 $8,769$6,678$3,431$5,056 $70,372$72,164$76,522$75,495 $5,680$6,112$7,196$6,971 $3,099$3,247$3,776$3,689 $15,000$15,000$15,000$15,000 ($1,309) $76,036 $194,583 $23,935 $294,553 $25,960 $13,810 $60,000 $0 $79,233 $209,971 $15,159 $304,363 $27,647 $14,609 $55,000 $0 $82,780 $219,622 $11,902 $314,304 $29,462 $15,457 $55,000 $0 $86,386 $234,900 $10,463 $331,749 $30,485 $16,045 $55,000 Adjusted EBITDAX$92,969$66,969$53,980$48,157 $262,076 $49,829$58,227$80,743$74,439 $263,238 $302,138 $334,074 $346,224 Total Capex$18,149$28,389$27,776$35,470 $109,784 $76,976$133,404$62,448$43,759 $316,587 $310,882 $312,572 $298,542 Unlevered Free Cash Flow$74,820$38,580$26,204$12,687 $152,291 ($27,147)($75,177)$18,295$30,680 ($53,349) ($8,744) $21,502 $47,682 UnSub Preferred Dividends + Interest$2,283$27,191$14,715$14,759 $58,948 $14,769$14,789$14,848$14,885 $59,291 $60,100 $61,337 $62,684 Free Cash Flow$72,536$11,389$11,489($2,072) $93,343 ($41,916)($89,966)$3,447$15,795 ($112,640) ($68,844) ($39,836) ($15,002)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION SN EF UnSub, (“UnSub”) LP 54

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Financial Highlights: Base Case (6/27/19 Strip Pricing) UnSub 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 $3 2019 2020 2021 2022 2023 2019 2020 2021 2022 2023 Note: Detailed financial forecast provided on page 56. (1) Includes interest on bank debt and preferred dividends. 55 $85 $69 $60 $57 $54 ($13) ($23) ($27) ($35) Levered Free Cash Flow ($MM) (1) Adjusted EBITDAX ($MM) 21.0 18.0 16.7 15.7 14.8 $26 $24 $23 $23 $23 Production (MBoe/d) Capital Expenditures ($MM)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Projections: Base Case (6/27/19 Strip Pricing) UnSub ($ in thousands) Note: All UnSub net production from Comanche asset. (1) Reflects an assumed allocation to UnSub of approximately $7.5 million for 2019 and $5 million per year thereafter, based on certain historical trends and future expectations. Actual G&A allocation between Restricted Group and UnSub may be more or less than the amounts shown, with such allocation determined in accordance with the applicable contract. 56 1Q 19 2Q 19 3Q 19 4Q 19 2019 1Q 20 2Q 20 3Q 20 4Q 20 2020 2021 2022 2023 Total Net Production (Boe/d)22,83721,34720,09819,599 Commodity Price: Oil ($/Bbl)$54.90$61.38$59.45$59.17 Gas ($/MMBtu)$3.15$2.56$2.32$2.45 NGL ($/Bbl)$27.82$23.66$21.54$23.96 Realized Price: Oil ($/Bbl)$55.21$60.90$58.95$58.68 Gas ($/Mcf)$3.20$2.66$2.41$2.54 NGL ($/Bbl)$17.11$13.29$12.08$13.44 Oil Revenue$40,913$38,073$34,689$33,684 Gas Revenue$12,035$9,679$8,372$8,625 NGL Revenue$11,768$9,461$8,226$8,923 20,959 $58.73 $2.62 $24.24 $58.27 $2.72 $13.98 $147,359 $38,711 $38,378 18,92218,08417,73717,401 $58.36$57.43$56.61$55.99 $2.67$2.42$2.49$2.61 $24.64$23.54$24.27$25.62 $57.87$56.94$56.14$55.51 $2.78$2.52$2.59$2.72 $13.82$13.20$13.61$14.37 $31,522$29,368$29,490$28,618 $9,030$7,857$7,908$8,129 $8,792$8,060$8,138$8,427 18,034 $57.10 $2.55 $24.52 $56.63 $2.65 $13.75 $118,999 $32,925 $33,417 16,677 $54.88 $2.60 $25.63 $54.42 $2.71 $14.38 $107,017 $30,764 $32,009 15,700 $54.16 $2.63 $25.81 $53.70 $2.73 $14.48 $101,328 $28,953 $30,071 14,767 $54.22 $2.70 $25.52 $53.77 $2.80 $14.31 $96,305 $27,828 $27,828 Oil, Gas, & NGL Revenue$64,716$57,214$51,287$51,231 $224,448 $49,344$45,286$45,537$45,175 $185,341 $169,790 $160,352 $151,961 Hedge Gain / (Loss) ($1,522)($2,684)($1,177)($1,329) LOE$10,539 $9,024$9,010 $8,924 Marketing$17,359$18,489$17,649$17,210 Deficiencies$0$857$1,127$1,169 Total Operating Expenses$27,897$28,370$27,786$27,303 Production Taxes$2,231$2,139$1,929$1,910 Ad Valorem Taxes$1,668$1,322$1,185$1,184 Cash G&A(1)$1,921$1,875$1,875$1,875 Reconciling Items to EBITDAX($39)$0$0$0 ($6,713) $37,497 $70,706 $3,153 $111,357 $8,210 $5,359 $7,546 ($39) ($1,497)($3)$1,205($1,013) $7,813$7,793$7,688$7,627 $16,461$15,769$15,530$15,235 $1,139$1,335$1,383$1,392 $25,413$24,897$24,602$24,254 $1,819$1,680$1,688$1,663 $1,141$1,047$1,052$1,044 $1,250$1,250$1,250$1,250 $0$0$0$0 ($1,309) $30,920 $62,996 $5,249 $99,165 $6,849 $4,284 $5,000 $0 $0 $29,989 $57,880 $6,293 $94,163 $6,238 $3,925 $5,000 $0 $0 $29,230 $54,218 $5,140 $88,587 $5,897 $3,707 $5,000 $0 $0 $28,687 $50,870 $4,151 $83,707 $5,589 $3,513 $5,000 $0 Adjusted EBITDAX$29,437$20,823$17,335$17,630 $85,226 $18,224$16,409$18,149$15,951 $68,734 $60,463 $57,162 $54,152 Total Capex$5,396$5,149$8,276$4,505 $23,326 $3,079$8,463$5,703$5,364 $22,608 $23,695 $22,527 $26,209 Unlevered Free Cash Flow$24,041$15,674$9,059$13,126 $61,900 $15,145$7,946$12,447$10,587 $46,126 $36,768 $34,635 $27,943 Preferred Dividends + Interest$2,283$27,191$14,715$14,759 $58,948 $14,769$14,789$14,848$14,885 $59,291 $60,100 $61,337 $62,684 Free Cash Flow$21,757($11,517)($5,656)($1,633) $2,951 $377($6,843)($2,402)($4,298) ($13,165) ($23,332) ($26,703) ($34,741)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION B. Corporate G&A Overview 57

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION G&A Allocation Process and Methodology Overview SN generally incurs G&A in two ways:  Directly in its own name (e.g., professional fees, various insurance policies and other SN agreements)  Indirectly based on estimated allocations from SOG (e.g., office/field staff and other services provided by SOG)  SOG is a service platform and allocates costs on a pass-through basis primarily to:  SN, without any mark-up  SNMP, with a 5% mark-up based on certain tax considerations  UnSub, subject to caps, with a 2% administrative fee which has historically been credited back to SN  Gavilan Resources, subject to caps, inclusive of a 2% administrative fee (MSA with Gavilan was terminated in March 2019)  Management compensation: management costs are generally allocated to the entities the individuals serve. For example, the SN CEO/CFO are allocated to SN, and the SNMP CEO/CFO are allocated to SNMP.  Employee compensation:  Employees are categorized based on their work assignment. Direct employees are allocated to the entities they serve, while indirect employees are allocated based on a twice-annual review of timesheets which record time spent serving each entity.  Most employees regularly complete timesheets, and SOG reviews a representative sample set of timesheets to determine the entity allocation that will be applied to the broader indirect employee group and other non-employee G&A items.  In addition, SN adheres to contractual MSA provisions to determine the amount of its overall G&A which may be allocated to UnSub and Gavilan with respect to the Comanche Assets.  SN advances funds to SOG at various intervals each month to cover its projected G&A allocation, giving consideration to the size and timing of expenses, such as payroll, lease payments and insurance premiums.  58

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary of 2018 SOG G&A Allocation Among Entities Allocated amounts generally include employee costs and other G&A expenses (e.g., corporate occupancy costs, contract labor and other overhead)  MSAs with respect to Comanche Assets ~$2 MM ~$7 MM MSA: SNMP and general partner SP Holdings, LLC MSA: SP Holdings and SOG 5% administrative fee ~$1 MM MSA dated 12/22/10 No administrative fee      Services Agreement dated 12/19/11 Contract Operating Agreement dated 12/19/11 License Agreement dated 12/19/11 Other contracts No administrative fee      ~$61 MM 59 Note: All amounts are based on cost accruals and represent base G&A allocations from SOG, unless otherwise indicated. Sanchez Energy Corporation Sanchez Oil & Gas Corporation ~$71 MM of G&A Allocated Sanchez Resources, LLC Sanchez Midstream Partners LP Sanchez Management MSA: SNCM and Gavilan dated 3/1/17  Back-to-back letter: SOG and SNCM MSA dated 3/1/17  Capped at $500k/mo. (incl. 2% admin. fee)Capped at $10 MM/yr. as of Mar. 2019 Terminated as of March 2019(plus 2% administrative fee) SN EF UnSub, LP Gavilan / SN Comanche Manager, LLC

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary of 2018 SN G&A Allocation Summary of G&A Allocated from SOG Summary of Other SN G&A + Field employees Other dedicated employees Total dedicated employees Management Corporate staff $8.0 2.6 Professional fees Information technology and software Board of Directors fees Company aircraft Investor relations / business development Other adjustments $33.7 5.4 1.5 2.1 2.1 -0.3 10.6 5.4 30.0 $105.4 MM Total allocated employees 35.5 Office rent / utilities 5.4 2.7 6.6 Contract labor Other overhead Other allocated G&A 14.7 Total allocation from SOG $60.8 for purposes of determining allocations to Gavilan and UnSub. $6.0 MM G&A allocation: 50% of est. Comanche cost, determined based on weighted average analysis of capex (70%) and well count (30%); results in ~53% of SN G&A allocated to Comanche G&A costs flow through SN; Gavilan pays SOG directly and SN receives credit Capped at $500k/mo. (including 2% admin. fee) MSA terminated as of March 2019 $5.0 MM + 2% admin. fee G&A allocation: 40% of est. incremental SN G&A following Comanche acquisition, net of Gavilan reimbursements G&A costs flow through SN; UnSub pays SN EF Maverick Capped at $5 MM/yr. through 3/1/19; $10 MM/yr. thereafter (plus 2% admin. fee) Balance of Comanche (after UnSub and Gavilan allocations)         Note: All amounts are based on cost accruals and represent base G&A allocations from SOG, unless otherwise indicated. (1) Net of COPAS allocation of ~$18.7 million. SN’s reported 2018 G&A was ~$98 million. 60 Summary of 2018 SN G&A Allocation: SN and SN EF Maverick$94.4 UnSub5.0 Gavilan6.0 Total SN G&A$105.4 (1) Sanchez Energy Corporation Total$44.6 46.6% 53.4% Total SN G&A is allocated between Comanche and Non-Comanche Non-Comanche Assets Comanche Assets SN: Catarina, Maverick and Palmetto Assets Gavilan Resources, LLC SN EF UnSub, LP SN EF Maverick, LLC $60.8 MM Allocated from SOG $44.6 MM Other SN G&A

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION C. Commodity Market Backdrop and Summary Capitalization 61

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Commodity Price Backdrop $120.00 $100.00 $80.00 $60.00 $54.59 $40.00 $20.00 $0.00 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 Historical Strip WTI Strip ($/Bbl) % Change Since Oct. 2018 Henry Hub Strip ($/MMBtu) % Change Since Oct. 2018 $58.99 (13.7%) $2.67 (10.0%) $55.98 (13.3%) $2.78 0.3% $54.75 (9.8%) $2.79 2.1% $54.59 (5.4%) $2.80 1.7% Source: Bloomberg and Capital IQ as of 6/26/19. Note: Strip prices listed in tables above are as of year-end (i.e., 2019 WTI strip is the monthly strip price for December 2019). 62 ($/Bbl) 2019202020212022 $58.99 $55.98 $54.75 WTI – Present (As of June 2019)

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Summary Capitalization SN Secured Debt: 1st Lien Credit Facility (1) 7.25% 1st Lien Notes Feb-23 Feb-23 --500 L+3.250% 7.250% $0 36 N/A 77.9¢ Total SN Secured Debt SN Unsecured Debt: 7.75% Notes 6.125% Notes $500 $36 Jun-21 Jan-23 $600 1,150 7.750% 6.125% $47 70 5.3¢ 4.2¢ Total SN Unsecured Debt $1,750 $117 UnSub Debt: 1st Lien UnSub Credit Facility Mar-22 $165 L+2.500% $9 N/A Total UnSub Debt $165 $9 Other Non-Recourse Debt: SR Credit Facility 4.59% Subsidiary Term Loan Aug-18 Aug-22 23 4 5.359% 4.590% $1 0 N/A N/A Total Non-Recourse Debt $27 $1 Preferred Securities: UnSub Preferred SN Series A Preferred (2) SN Series B Preferred (2) $500 39 126 10.000% 4.875% 6.500% $50 3 8 N/A $0.21 $0.10 Total Preferred Securities $665 $61 Source: Bloomberg and Capital IQ as of 6/26/19. Note: Please refer to the Company's SEC filings for a complete description of its capitalization and outstanding securities. (1) Represents a $25 million first lien, first-out working capital and letter of credit facility, of which approximately $17 million is currently utilized for an outstanding letter of credit issued in January 2019. (2) Series A and Series B preferred outstanding amounts reflect a liquidation preference of $50/share. 63 Total Debt$2,442$164 Total SN Recourse Debt$2,250$153 AmountInterestInterestMarket ($mm)MaturityOutstandingRateExpensePrice

STRICTLY CONFIDENTIAL – SUBJECT TO CONFIDENTIALITY AGREEMENTS – PRELIMINARY – SUBJECT TO SUBSTANTIAL REVISION Non-GAAP Financial Measure Reconciliation 1Q 2019 Consolida te d Re stricte d UnSub Elimina tions Entity Adj./Othe r Reconciliation Table: Reported net income (loss) Plus: Interest expense Amortization of debt issuance costs Net (gains) losses on commodity derivative contracts Net settlements paid on commodity derivative contracts Exploration expense Depreciation, depletion, amortization and accretion Impairment of oil and natural gas properties Non-cash stock-based compensation (benefit) expense Income tax expense (Gains) losses on other derivatives (Gains) losses on investments Gains on disposal of assets Interest income $ (67.3) $ (45.6) $ (19.7) $ (3.2) $ 1.2 44.6 - 48.4 (3.5) 1.3 67.5 3.9 0.1 0.4 (0.3) (1.5) - (0.6) 38.8 2.2 18.1 (2.0) 1.1 47.3 3.7 0.1 0.4 (0.3) - - (0.2) 2.3 1.0 30.4 (1.5) 0.2 16.9 - - - - - - - - - - - - 3.1 - - - - - - - 3.4 (3.2) - - - 0.3 0.2 - - - (1.5) - (0.4) Adjusted EBITDAX $ 93.0 $ 63.6 $ 29.4 Plus: Incurred capital expenditures (18.1) (12.8) (5.4) Unlevered Free Cash Flow $ 74.8 $ 50.9 $ 24.0 Plus: Cash paid preferred dividends & interest at UnSub (2.3) (2.3) Free Cash Flow $ 72.5 $ 50.9 $ 21.8 Adjusted EBITDAX, Unlevered Free Cash Flow and Free Cash Flow are non-GAAP financial measures that are used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance as compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures. Our Adjusted EBITDAX, Unlevered Free Cash Flow and Free Cash Flow should not be considered an alternative to net income (loss), operating income (loss), cash flows provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with U.S. GAAP. Our Adjusted EBITDAX, Unlevered Free Cash Flow and Free Cash Flow may not be comparable to similarly titled measures of another company because all companies may not calculate these non-GAAP financial measures in the same manner. 64 Adjusted EBITDAX, Unlevered Free Cash Flow and Free Cash Flow Reconciliation