Exhibit 99.1

www.sanchezenergycorp.com Results Driven. Manufacturing Focused. Sanchez Energy Business Plan March 2020 January 23, 2017

2 Management Representatives Mo Meghji Chief Restructuring Officer Cam George Executive Vice President and Chief Financial Officer Greg Kopel Executive Vice President, General Counsel and Secretary Mike Blincow Vice President, Production Scott Dunlap Vice President, Drilling and Completions Holly Griffin Director, Asset Development Cham King Director, Finance and Business Development Scott Wike Director, Marketing Cheyne Hermes Manager, Corporate Finance and Strategy

I. Executive Summary 4 II. Business Plan and Financial Projections 8 III. Asset Development Plan 20 IV. Midstream 26 V. Corporate G&A 29 Appendix A. PDP Reference Case 32 B. Other Supporting Items 34 3 Table of Contents

I. Executive Summary 4 4

Business Plan Approach and Summary The Sanchez Energy management team and advisors (SN, or the Company) have been working diligently on a revised business p lan , with the goal of maximizing value for stakeholders by focusing on (1) disciplined and optimized capital spend, (2) preservation of optionality fo r longer - term value realization (with key decision points clearly identified), (3) a simplified and reduced overhead cost structure and (4) a com pre hensive midstream solution 5 Approach and Objectives: The Company has put together the principal building blocks of a proposed, going concern business plan for the future owners of the Company, with a primary focus on asset development, midstream and corporate overhead expenses The Company has explored three cases that bookend possible scenarios for the development of the asset base The Option Preservation Case assumes drilling at Catarina to hold the lease through June 2021 (but no longer) and full participation/operatorship at Comanche The Accelerated Completions Case assumes completing the drilled but uncompleted wells (DUCs) at Catarina, full participation/operatorship at Comanche and no further participation in future drilling across the rest of the asset base The PDP Reference Case assumes completing the drilled but uncompleted wells at Catarina, no participation in future drilling across the rest of the as set base and loss of Comanche operatorship The Company and its advisors are exploring any combination or variants of these cases that maximize value and optionality This process has included significant review, diligence and revisions to the Company’s previous plan, with work still ongoing to identify additional upside All forecasts are preliminary, and conclusions are subject to change based on further and ongoing assessments Nothing in this presentation is intended to be a valuation or reflect the Company’s or any Company advisor’s view on valuatio n Key Building Blocks: 1. Asset Development Catarina: Option Preservation Case: Retain unique, single ~106,000 acre Catarina lease through 2021 by satisfying current leasehold com mit ments, but no further drilling after June 2020 (all locations are uneconomic at current prices, and continued activity at historical levels wo uld require a substantial commodity recovery) Accelerated Completions Case: Complete remaining 31 DUCs Comanche: Retain operatorship of entire, multi - lease asset and focus development on highest rate of return opportunities (~50 - 80 wells per year) At the request of the CRO, the Company’s reserves, engineering and development plan assumptions were independently reviewed b y t he Debtor advisors’ technical and E&P teams • The technical and E&P teams did not find any variances that would materially change assumptions • Feedback has also been solicited from creditor groups, with viable suggestions to be further considered and, if appropriate, inc orporated The overarching focus is on a near - term path to free cash flow generation while preserving longer term option value/upside where economically justified • We believe this can be achieved through disciplined capital spend on high - graded inventory and leasehold retention wells only See asset development section for additional detail on operational strategy

Business Plan Approach and Summary (continued) 6 Key Building Blocks (continued) : 2. Midstream and Marketing A contract - by - contract financial model was created by SN’s midstream team, with no involvement from Sanchez Midstream Partners L P (SNMP) related personnel, to help inform midstream optimization strategy • A comprehensive analysis regarding the value of midstream contract optimization is ongoing The SECO pipeline contract with SNMP was terminated on January 13, 2020 (30 - day notice provided to SNMP) 3. Corporate G&A A revised G&A plan has been created and evaluated on a bottom - up basis by the Company and its advisors

Business Plan Approach and Summary (continued) 7 Preliminary Conclusions : Preliminary analysis indicates higher asset value under the Option Preservation and Accelerated Completions Cases when compar ed to the PDP Reference Case The Company believes a going concern business model that drills only economic or leasehold retention wells (as part of a near - te rm option preservation strategy) provides the best opportunity to maximize value for stakeholders While the intentions and preferences of creditors are likely to shape the longer - term business plan, the Company believes a focu sed operating business provides stakeholders with potential upside opportunities for NAV accretion, as opposed to the PDP Reference Case The material building blocks of the preliminary business plans are subject to additional input and consideration from the fut ure owners of SN (whether they be the creditors or a new buyer), and therefore the assumptions used in these plans are subject to change Open Issues, Ongoing Business Initiatives and Next Steps : 1. Net asset value figures contained throughout the presentation have been prepared using the Company’s corporate model and corr esp onding ARIES database, both of which are subject to continuous review and revision by the Company 2. Ryder Scott is reviewing PDP and PUD forecasts for the Company’s year end reserve report 3. Further legal and financial analysis on midstream strategy 4. Potential negotiation with Catarina landowner 5. Discussions with creditor groups around optimal development plan assumptions 6. Potential capital structure at emergence (e.g., DIP refinancing, reinstated debt, etc.), which is not addressed by the curren t b usiness plan 7. Address issues of all other key stakeholders and counterparties, such as Sanchez Oil & Gas Corporation (SOG), Gavilan Resources LLC ( Gavilan ), SNMP, GSO Capital Partners, etc. 8. The business plan may be further revised based on ongoing analysis in the context of maximizing value for the estate

II. Business Plan and Financial Projections 8 8

Business Plan Assumptions 9 Assumption Commentary Commodity Prices Strip pricing as of 2/11/20 Realized prices vs. benchmark prices (WTI and Henry Hub): oil (~93% - 98%), natural gas (~100%) and NGLs (~15% of WTI oil price) Midstream/Marketing Option Preservation, Accelerated Completions and PDP Reference Cases assume current contracts remain in place (i.e., status q uo) SECO contract terminated with 30 - day notice to SNMP in January 2020 Interruptible gathering rates at Eastern Catarina are held flat at current rate of $1.50/ Mcf Corporate G&A Projected G&A profile is illustrative; assumes streamlined cost structure, renegotiated office lease and elimination of all n on - core expenses under private company emergence assumption Gross G&A projection in the Option Preservation and Accelerated Completions Cases is reduced to approximately $35 - $40MM, before adjustment for COPAS recovery The operator of oil and gas properties is generally entitled to receive COPAS recovery for reimbursement of expenses incurred on behalf of the other working interest owners of those properties; COPAS recovery to SN from operating Comanche is governed by the JOA and assumed at approximately $950 per well; 3% annual escalation of COPAS reimbursement based on 10 - year historical average Other Operating Expenses/Taxes Based on 12 - month historical averages for each asset from the lease operating statements (LOS) Ad valorem and severance tax rates are based on latest county estimates as a percentage of production Catarina Option Preservation Case: Meet drilling requirement (24 additional wells) by June 2020; hold Catarina lease through June 2021; complete all drilled but uncompleted wells (DUCs) over the next ~18 months Accelerated Completions Case: complete remaining DUCs by June 2020 Comanche High - graded and optimized development schedule for Comanche drilling (~50 - 80 wells per year for next 6 - 8 years) Focus on highest IRR wells within each type curve area, while meeting lease obligations; retains all material leases Ring - fenced, non - debtor subsidiary SN EF UnSub, LP (UnSub) continues to self - fund its portion of new Comanche development spen d Other Assets Maverick – undeveloped wells uneconomic at current commodity prices; plan assumes PDP only resulting in significant lease expira tions Palmetto – non - consent 2020 development capital (10 wells with unproven type curves with net cost to SN of ~$40 million); potent ial upside from future option to participate in years 2021+ once well economics have been demonstrated. Non - consenting 2020 development program does not forfeit opportunity to participate in 2021+ development wells Other non - core assets include the Company’s Tuscaloosa Marine Shale (TMS) assets and assets operated by others (OBO) Well Economics Assumes current authorization for expenditure (AFE) estimates based on average lateral length Corporate model calculates the cost of every well with specific adjustments for lateral length Well costs supported by historical averages The Company and its advisors have conducted a thorough review of business plan assumptions

$ millions Summary NAV Analysis (1) $50/$2.50 Strip (2) $60/$2.50 $70/$2.50 $80/$2.50 Asset Values (PV-10): Catarina (3) $149 $186 $283 $417 $551 Comanche (Restricted Only) (4) $49 $77 $140 $230 $321 Maverick $78 $83 $103 $129 $154 Palmetto $8 $8 $11 $14 $17 OBO / Other $3 $3 $4 $5 $5 Asset Value (Pre-G&A) $288 $357 $541 $795 $1,048 Total G&A (5) ($95) ($95) ($95) ($95) ($95) Asset Value (Post-G&A) $193 $262 $446 $700 $953 Est. Upside from Palmetto Participation (6) $5 $7 $17 $28 $40 Optimized/Upside Asset Value $198 $269 $463 $728 $993 Summary NAV Analysis (1) $50/$2.50 Strip (2) $60/$2.50 $70/$2.50 $80/$2.50 Asset Values (PV-10): Catarina (3) $197 $225 $313 $429 $544 Comanche (Restricted Only) (4) $49 $77 $140 $230 $321 Maverick $78 $83 $103 $129 $154 Palmetto $8 $8 $11 $14 $17 OBO / Other $3 $3 $4 $5 $5 Asset Value (Pre-G&A) $336 $396 $571 $806 $1,042 Total G&A (5) ($95) ($95) ($95) ($95) ($95) Asset Value (Post-G&A) $241 $301 $476 $711 $947 Est. Upside from Palmetto Participation (6) $5 $7 $17 $28 $40 Optimized/Upside Asset Value $246 $308 $493 $739 $986 Summary NAV Analysis (1)(7) $50/$2.50 Strip (2) $60/$2.50 $70/$2.50 $80/$2.50 Asset Values (PV-10): Catarina (3) $197 $225 $313 $429 $544 Comanche (Restricted Only) (4)(8) ($19) ($12) $21 $61 $100 Maverick $78 $83 $103 $129 $154 Palmetto $8 $8 $11 $14 $17 OBO / Other $3 $3 $4 $5 $5 Asset Value (Pre-G&A) $268 $308 $452 $637 $821 Total G&A (5) ($223) ($223) ($223) ($223) ($223) Asset Value (Post-G&A) $45 $85 $230 $414 $599 Option Preservation Case Accelerated Completions Case PDP Reference Case NAV (PV - 10) Analysis and Comparison 10 Notes: All values are preliminary and are calculated based on a 5/31/20 effective date. Strip values were run through the Com pan y’s ARIES database. The flat price deck sensitivities are for estimation purposes only. These sensitivities were run in the Excel model which ties closely to the ARIES database but lacks the ability to extend the lif e of individual wells and/or shut - in production based on pricing (referred to as LOSSNO). (1) Valuation excludes estimated cash at emergence. Estimated at approximately $27MM for SN Operating and UR Holdings accounts. (2) Strip pricing as of 2/11/20. (3) The estimated split of PV - 10 at strip between Central/Eastern and Western Catarina in the Option Preservation Case is 52% ($157M M) and 48% ($142MM), respectively. The estimated PV - 10 split ignores field level expenses that are allocated to the entire field (PV - 10 - $101MM) and non - D&C capital ( - $12MM). The estimated total production spl it between Central/Eastern and Western Catarina is 43% and 57%, respectively. Note that blended marketing and LOE rates are applied to all wells. For the Accelerated Completions and PDP Reference Cases, the PV - 10 split is Central/Eastern 47% ($158MM) and Western 53% ($181MM). (4) Includes Springfield marketing bands. (5) Represents 30 - year PV - 10 of corporate G&A. Includes COPAS recovery PV - 10 impact of ~$245MM (Option Preservation), ~$245mm (Accel erated Completions) and $6MM (PDP Reference) for each scenario. Of the COPAS recovery PV - 10 impact in the Option Preservation and Accelerated Completions cases, ~21% is attributable to UnSub and ~79% to 3 rd parties. (6) Assumes 50% non - operated participation in remaining economic type curve areas (estimated 11 well inventory) if initial 2020 well results are in - line with Marathon expectations; wells are assumed to be drilled and completed during 2021 - 2023 and are not included in Option Preservation, Accelerated Completions or PDP Blowdown Reference Case. (7) Excludes any estimated upside from Palmetto participation as the blowdown case assumes no further D&C capital investment. Pot ent ial upside if another operator executes SN’s current development plan. (8) Assumes no development activity as another operator’s plan/budget cannot be forecasted. All forecasts are preliminary, and conclusions are subject to change based on further and ongoing assessments Nothing in this presentation is intended to be a valuation or reflect the Company’s or any Company advisor’s view on valuation

Illustrative and Preliminary NAV (PV - 10) Sensitivities 11 PV - 10 for Option Preservation Case, Accelerated Completions Case and PDP Case at Various Price Decks (1) (2)(3) Notes: All values are preliminary and are calculated based on a 5/31/20 effective date. Strip values were run through the Com pan y’s ARIES database. The flat price deck sensitivities are for estimation purposes only. These sensitivities were run in the Excel model which ties closely to the ARIES database but lacks the ability to extend the lif e of individual wells and/or shut - in production based on pricing (referred to as LOSSNO). (1) Mt. Belvieu Propane is assumed to proportionately increase with WTI (32% of WTI); this results in average realized SN NGL bas ket pricing of approximately 15% of WTI. (2) Asset values after G&A (excludes Palmetto participation). (3) Values excludes estimated cash at emergence. (4) Strip pricing as of 2/11/20. ($ in millions) $50 Strip (4) $60 $70 $80 $2.25 $158 $199 $412 $665 $919 Strip (4) $189 $262 $443 $696 $950 $2.50 $193 $233 $446 $700 $953 $2.75 $227 $268 $481 $734 $988 $3.00 $262 $302 $515 $769 $1,022 $50 Strip (4) $60 $70 $80 $2.25 $209 $247 $444 $679 $914 Strip (4) $237 $301 $472 $708 $943 $2.50 $241 $279 $476 $711 $947 $2.75 $273 $311 $508 $744 $979 $3.00 $305 $343 $541 $776 $1,011 $50 Strip (4) $60 $70 $80 $2.25 $18 $46 $202 $387 $571 Strip (4) $40 $85 $225 $409 $594 $2.50 $45 $73 $230 $414 $599 $2.75 $73 $101 $257 $442 $626 $3.00 $100 $128 $285 $469 $654 Gas Price (HH) Oil Price (WTI) – Option Preservation Gas Price (HH) Oil Price (WTI) – Accelerated Completions Gas Price (HH) Oil Price (WTI) – PDP Reference Case

Option Preservation Case Financial Projections (Accrual) 12 Notes: Represents consolidated cash flow forecast net to Debtors. Presented on an accrual basis. Strip pricing as of 2/11/20 . (1) Q4 2019 quarter actuals are estimates and subject to change upon finalized earnings. (2) Represents non - cash, non - recurring and other amounts included in the above line items which are traditionally added back or excluded in the determination of Adjusted EBITDAX. The amount primarily reflects restructuring fees and certain non - cash adjustments . (3) Production volumes from ARIES database may not tie exactly to the company model. Pre- Emergence Post- Emergence Jan-May Jun-Dec Full Year $ millions 2017A 2018A 2019E (1) 2020E 2020E 2020E 2021E 2022E 2023E 2024E Oil (Boe/d) 15,085 18,026 14,949 11,070 11,891 11,520 12,391 9,871 8,959 8,551 Gas (Mcf/d) 104,638 105,400 89,143 70,384 72,356 71,344 76,633 62,844 54,925 51,322 NGL (Boe/d) 15,171 18,762 15,829 13,193 13,553 13,367 14,357 11,847 10,410 9,789 Total Net Daily Production (Boe/d) 47,695 54,355 45,635 35,993 37,503 36,778 39,520 32,193 28,523 26,893 Benchmark Commodity Prices: WTI ($/Bbl) $50.97 $64.66 $57.02 $51.65 $51.00 $51.27 $50.89 $50.96 $51.32 $51.69 Henry Hub ($/Mcf) $3.11 $3.11 $2.60 $1.87 $2.13 $2.02 $2.36 $2.41 $2.45 $2.47 Mt. Belvieu Propane ($/Bbl) $20.48 $23.45 $22.46 $16.36 $17.86 $17.24 $18.45 $18.93 $19.30 $19.43 Realized Commodity Prices: Oil ($/Bbl) $49.47 $65.73 $56.34 $49.51 $48.66 $49.00 $48.39 $48.70 $49.22 $49.71 Gas ($/Mcf) $3.17 $3.14 $2.67 $1.85 $2.11 $2.01 $2.33 $2.39 $2.44 $2.45 NGL ($/Bbl) $21.10 $23.39 $14.09 $8.32 $9.08 $8.79 $9.33 $9.51 $9.61 $9.58 Oil Revenue $272 $432 $307 $83 $124 $207 $219 $175 $161 $156 Gas Revenue 121 121 87 20 33 52 65 55 49 46 NGL Revenue 117 160 81 17 26 43 49 41 37 34 Other Sales and Marketing Revenue --- 26 18 --- --- --- --- --- --- --- Oil, Gas, & NGL Revenue $510 $739 $494 $119 $183 $302 $333 $271 $246 $236 Hedge Gain / (Loss) $5 $(86) $8 $ --- $ --- $ --- $ --- $ --- $ --- $ --- Other Sales and Marketing Expenses --- (24) (17) --- --- --- --- --- --- --- Lease Operating Expenses (49) (64) (43) (13) (19) (32) (32) (30) (29) (29) Marketing (108) (131) (160) (58) (86) (144) (145) (122) (103) (92) Production Taxes (18) (30) (18) (5) (7) (12) (13) (11) (10) (10) Ad Valorem Taxes (5) (10) (10) (2) (4) (6) (7) (6) (5) (5) Corporate G&A (114) (87) (89) (25) (13) (38) (15) (15) (14) (14) Restructuring & Chapter 11 Fees --- --- (83) (61) --- (61) --- --- --- --- Total G&A (114) (87) (173) (86) (13) (99) (15) (15) (14) (14) Reconciling Items to EBITDAX (2) 28 (6) 87 61 --- 61 --- --- --- --- Adjusted EBITDAX $249 $302 $167 $15 $54 $69 $121 $88 $84 $86 EBITDA Margin (%) 49% 41% 34% 13% 29% 23% 36% 32% 34% 37% Memo: Total Operating Expenses $(261) $(437) $(327) $(104) $(129) $(233) $(212) $(183) $(162) $(150) Capex $(485) $(512) $(62) $(70) $(79) $(149) $(113) $(50) $(47) $(47) Adjusted EBITDAX Less Capex $(236) $(210) $105 $(55) $(25) $(80) $8 $38 $37 $39 Restructuring & Chapter 11 Fees $ --- $ --- $(83) $(61) $ --- $(61) $ --- $ --- $ --- $ --- Unlevered Cash Flow (after Ch. 11 Fees) $(236) $(210) $21 $(115) $(25) $(141) $8 $38 $37 $39 Memo: Catarina Central / East Volumes (Boe/d) (3) 12,857 13,815 10,388 8,301 7,036 Memo: COPAS Recovery/(Payment) - 3rd Parties $11 $19 $16 $6 $9 $16 $16 $17 $18 $19 Memo: COPAS Recovery/(Payment) - UnSub $2 $4 $4 $2 $3 $5 $5 $5 $5 $5

Option Preservation Case 2020E Financial Projections (Accrual) 13 Notes: Represents consolidated cash flow forecast net to Debtors. Presented on an accrual basis. Strip pricing as of 2/11/20. (1) Represents non - cash, non - recurring and other amounts included in the above line items which are traditionally added back or excluded in the determination of Adjusted EBITDAX. The amount primarily reflects restructuring fees and certain non - cash adjustments. (2) Production volumes from ARIES database may not tie exactly to the company model. $ millions Jan 2020E Feb 2020E Mar 2020E Apr 2020E May 2020E Jun 2020E Jul 2020E Aug 2020E Sep 2020E Oct 2020E Nov 2020E Dec 2020E FY 2020E Oil (Boe/d) 11,012 10,767 10,819 11,392 10,993 10,614 10,097 13,294 13,388 12,566 11,896 11,389 11,520 Gas (Mcf/d) 71,001 69,446 67,779 71,511 69,886 68,105 64,354 74,784 79,188 75,921 73,337 70,914 71,344 NGL (Boe/d) 13,294 13,007 12,706 13,412 13,114 12,780 12,080 13,997 14,803 14,207 13,735 13,286 13,367 Total Net Daily Production (Boe/d) 36,139 35,349 34,822 36,723 35,755 34,745 32,903 39,756 41,389 39,427 37,854 36,494 36,778 Benchmark Commodity Prices: WTI ($/Bbl) $57.53 $50.18 $49.94 $50.17 $50.45 $50.68 $50.88 $51.01 $51.07 $51.11 $51.14 $51.11 $51.27 Henry Hub ($/Mcf) $2.02 $1.83 $1.79 $1.82 $1.88 $1.95 $2.03 $2.07 $2.07 $2.11 $2.24 $2.46 $2.02 Mt. Belvieu Propane ($/Bbl) $18.06 $15.52 $16.01 $16.07 $16.17 $16.01 $17.17 $17.59 $18.01 $18.38 $18.74 $19.11 $17.24 Realized Commodity Prices: Oil ($/Bbl) $55.18 $48.13 $47.88 $48.05 $48.34 $48.57 $48.77 $48.51 $48.53 $48.68 $48.76 $48.77 $49.00 Gas ($/Mcf) $2.00 $1.82 $1.77 $1.81 $1.87 $1.94 $2.01 $2.05 $2.05 $2.09 $2.22 $2.44 $2.01 NGL ($/Bbl) $9.20 $7.90 $8.14 $8.16 $8.20 $8.12 $8.71 $8.96 $9.19 $9.36 $9.53 $9.71 $8.79 Oil Revenue $19 $15 $16 $16 $16 $15 $15 $20 $19 $19 $17 $17 $207 Gas Revenue 4 4 4 4 4 4 4 5 5 5 5 5 52 NGL Revenue 4 3 3 3 3 3 3 4 4 4 4 4 43 Other Sales and Marketing Revenue --- --- --- --- --- --- --- --- --- --- --- --- --- Oil, Gas, & NGL Revenue $27 $22 $23 $24 $24 $23 $23 $29 $28 $28 $26 $27 $302 Hedge Gain / (Loss) $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- Other Sales and Marketing Expenses --- --- --- --- --- --- --- --- --- --- --- --- --- Lease Operating Expenses (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (32) Marketing (12) (11) (12) (12) (12) (11) (11) (13) (13) (13) (12) (12) (144) Production Taxes (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (12) Ad Valorem Taxes (1) (0) (0) (0) (0) (0) (0) (1) (1) (1) (1) (1) (6) Corporate G&A (5) (5) (5) (5) (5) (5) (1) (1) (1) (1) (1) (1) (38) Restructuring & Chapter 11 Fees (9) (8) (9) (9) (26) --- --- --- --- --- --- --- (61) Total G&A (13) (13) (14) (14) (32) (5) (1) (1) (1) (1) (1) (1) (99) Reconciling Items to EBITDAX (1) 9 8 9 9 26 --- --- --- --- --- --- --- 61 Adjusted EBITDAX $6 $2 $3 $2 $2 $2 $6 $10 $9 $9 $8 $9 $69 EBITDA Margin (%) 22% 9% 11% 10% 10% 8% 27% 34% 33% 33% 32% 33% 23% Memo: Total Operating Expenses $(21) $(20) $(20) $(21) $(21) $(21) $(17) $(19) $(19) $(19) $(18) $(18) $(233) Capex $(8) $(22) $(16) $(14) $(10) $(36) $(20) $(7) $(3) $(3) $(5) $(4) $(149) Adjusted EBITDAX Less Capex $(2) $(20) $(14) $(12) $(7) $(34) $(14) $3 $6 $6 $3 $4 $(80) Restructuring & Chapter 11 Fees $(9) $(8) $(9) $(9) $(26) $ --- $ --- $ --- $ --- $ --- $ --- $ --- $(61) Unlevered Cash Flow (after Ch. 11 Fees) $(10) $(28) $(22) $(21) $(33) $(34) $(14) $3 $6 $6 $3 $4 $(141) Memo: Catarina Central / East Volumes (Boe/d) (2) 13,137 13,587 12,317 12,350 13,694 13,478 12,522 12,078 13,931 12,793 12,664 11,808 12,857 Memo: COPAS Recovery/(Payment) - 3rd Parties $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.4 $1.4 $1.4 $15.7 Memo: COPAS Recovery/(Payment) - UnSub $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $4.5

Accelerated Completions Case Financial Projections (Accrual) 14 Pre- Emergence Post- Emergence Jan-May Jun-Dec Full Year $ millions 2017A 2018A 2019E (1) 2020E 2020E 2020E 2021E 2022E 2023E 2024E Oil (Boe/d) 15,085 18,026 14,949 11,374 12,941 12,259 9,949 8,658 8,212 8,001 Gas (Mcf/d) 104,638 105,400 89,143 72,128 79,765 76,396 64,498 55,569 50,308 47,897 NGL (Boe/d) 15,171 18,762 15,829 13,515 14,919 14,299 12,118 10,505 9,558 9,157 Total Net Daily Production (Boe/d) 47,695 54,355 45,635 36,910 41,155 39,291 32,817 28,425 26,154 25,140 Benchmark Commodity Prices: WTI ($/Bbl) $50.97 $64.66 $57.02 $51.65 $51.00 $51.27 $50.89 $50.96 $51.32 $51.69 Henry Hub ($/Mcf) $3.11 $3.11 $2.60 $1.87 $2.13 $2.02 $2.36 $2.41 $2.45 $2.47 Mt. Belvieu Propane ($/Bbl) $20.48 $23.45 $22.46 $16.36 $17.86 $17.24 $18.45 $18.93 $19.30 $19.43 Realized Commodity Prices: Oil ($/Bbl) $49.47 $65.73 $56.34 $49.48 $48.55 $48.90 $48.66 $48.89 $49.36 $49.82 Gas ($/Mcf) $3.17 $3.14 $2.67 $1.85 $2.11 $2.01 $2.34 $2.39 $2.44 $2.45 NGL ($/Bbl) $21.10 $23.39 $14.09 $8.33 $9.10 $8.80 $9.33 $9.47 $9.57 $9.54 Oil Revenue $272 $432 $307 $85 $134 $219 $177 $154 $148 $146 Gas Revenue 121 121 87 20 36 56 55 49 45 43 NGL Revenue 117 160 81 17 29 46 41 36 33 32 Other Sales and Marketing Revenue --- 26 18 --- --- --- --- --- --- --- Oil, Gas, & NGL Revenue $510 $739 $494 $122 $199 $322 $273 $239 $226 $221 Hedge Gain / (Loss) $5 $(86) $8 $ --- $ --- $ --- $ --- $ --- $ --- $ --- Other Sales and Marketing Expenses --- (24) (17) --- --- --- --- --- --- --- Lease Operating Expenses (49) (64) (43) (13) (19) (32) (30) (29) (29) (29) Marketing (108) (131) (160) (58) (92) (149) (131) (112) (96) (87) Production Taxes (18) (30) (18) (5) (8) (13) (11) (10) (9) (9) Ad Valorem Taxes (5) (10) (10) (3) (4) (7) (6) (5) (5) (5) Corporate G&A (114) (87) (89) (25) (13) (38) (15) (15) (14) (14) Restructuring & Chapter 11 Fees --- --- (83) (61) --- (61) --- --- --- --- Total G&A (114) (87) (173) (86) (13) (99) (15) (15) (14) (14) Reconciling Items to EBITDAX (2) 28 (6) 87 61 --- 61 --- --- --- --- Adjusted EBITDAX $249 $302 $167 $18 $63 $82 $79 $68 $73 $78 EBITDA Margin (%) 49% 41% 34% 15% 32% 25% 29% 29% 32% 35% Memo: Total Operating Expenses $(261) $(437) $(327) $(104) $(136) $(240) $(194) $(171) $(153) $(143) Capex $(485) $(512) $(62) $(97) $(28) $(125) $(38) $(50) $(47) $(47) Adjusted EBITDAX Less Capex $(236) $(210) $105 $(78) $35 $(43) $41 $18 $26 $31 Restructuring & Chapter 11 Fees $ --- $ --- $(83) $(61) $ --- $(61) $ --- $ --- $ --- $ --- Unlevered Cash Flow (after Ch. 11 Fees) $(236) $(210) $21 $(139) $35 $(104) $41 $18 $26 $31 Memo: Catarina Central / East Volumes (Boe/d) (3) 13,779 10,754 8,431 7,073 6,127 Memo: COPAS Recovery/(Payment) - 3rd Parties $11 $19 $16 $6 $9 $16 $16 $17 $18 $19 Memo: COPAS Recovery/(Payment) - UnSub $2 $4 $4 $2 $3 $5 $5 $5 $5 $5 Notes: Represents consolidated cash flow forecast net to Debtors. Presented on an accrual basis . Strip pricing as of 2/11/20. (1) Q4 2019 quarter actuals are estimates and subject to change upon finalized earnings. (2) Represents non - cash, non - recurring and other amounts included in the above line items which are traditionally added back or excluded in the determination of Adjusted EBITDAX. The amount primarily reflects restructuring fees and certain non - cash adjustments . (3) Production volumes from ARIES database may not tie exactly to the company model.

Accelerated Completions Case 2020E Financial Projections (Accrual) 15 Notes: Represents consolidated cash flow forecast net to Debtors. Presented on an accrual basis. Strip pricing as of 2/11/20. (1) Represents non - cash, non - recurring and other amounts included in the above line items which are traditionally added back or excluded in the determination of Adjusted EBITDAX. The amount primarily reflects restructuring fees and certain non - cash adjustments. (2) Production volumes from ARIES database may not tie exactly to the company model. $ millions Jan 2020E Feb 2020E Mar 2020E Apr 2020E May 2020E Jun 2020E Jul 2020E Aug 2020E Sep 2020E Oct 2020E Nov 2020E Dec 2020E FY 2020E Oil (Boe/d) 11,012 10,767 10,644 11,623 12,428 12,009 15,829 13,954 12,858 12,432 11,933 11,509 12,259 Gas (Mcf/d) 71,001 69,446 67,040 71,719 78,922 74,899 90,310 85,047 80,876 78,045 75,643 73,279 76,396 NGL (Boe/d) 13,294 13,007 12,570 13,451 14,781 14,033 16,869 15,890 15,115 14,599 14,161 13,722 14,299 Total Net Daily Production (Boe/d) 36,139 35,349 34,387 37,027 40,363 38,525 47,749 44,019 41,452 40,039 38,701 37,444 39,291 Benchmark Commodity Prices: WTI ($/Bbl) $57.53 $50.18 $49.94 $50.17 $50.45 $50.68 $50.88 $51.01 $51.07 $51.11 $51.14 $51.11 $51.27 Henry Hub ($/Mcf) $2.02 $1.83 $1.79 $1.82 $1.88 $1.95 $2.03 $2.07 $2.07 $2.11 $2.24 $2.46 $2.02 Mt. Belvieu Propane ($/Bbl) $18.06 $15.52 $16.01 $16.07 $16.17 $16.01 $17.17 $17.59 $18.01 $18.38 $18.74 $19.11 $17.24 Realized Commodity Prices: Oil ($/Bbl) $55.18 $48.13 $47.90 $48.02 $48.18 $48.40 $48.25 $48.45 $48.57 $48.69 $48.76 $48.76 $48.90 Gas ($/Mcf) $2.00 $1.82 $1.77 $1.81 $1.87 $1.93 $2.01 $2.05 $2.05 $2.09 $2.22 $2.44 $2.01 NGL ($/Bbl) $9.20 $7.90 $8.14 $8.16 $8.23 $8.14 $8.77 $8.98 $9.19 $9.36 $9.54 $9.72 $8.80 Oil Revenue $19 $15 $16 $17 $19 $17 $24 $21 $19 $19 $17 $17 $219 Gas Revenue 4 4 4 4 5 4 6 5 5 5 5 6 56 NGL Revenue 4 3 3 3 4 3 5 4 4 4 4 4 46 Other Sales and Marketing Revenue --- --- --- --- --- --- --- --- --- --- --- --- --- Oil, Gas, & NGL Revenue $27 $22 $23 $24 $27 $25 $34 $31 $28 $28 $27 $27 $322 Hedge Gain / (Loss) $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- $ --- Other Sales and Marketing Expenses --- --- --- --- --- --- --- --- --- --- --- --- --- Lease Operating Expenses (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (3) (32) Marketing (12) (11) (11) (11) (13) (12) (15) (14) (13) (13) (12) (12) (149) Production Taxes (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (13) Ad Valorem Taxes (1) (0) (0) (0) (1) (1) (1) (1) (1) (1) (1) (1) (7) Corporate G&A (5) (5) (5) (5) (5) (5) (1) (1) (1) (1) (1) (1) (38) Restructuring & Chapter 11 Fees (9) (8) (9) (9) (26) --- --- --- --- --- --- --- (61) Total G&A (13) (13) (14) (14) (32) (5) (1) (1) (1) (1) (1) (1) (99) Reconciling Items to EBITDAX (1) 9 8 9 9 26 --- --- --- --- --- --- --- 61 Adjusted EBITDAX $6 $2 $3 $3 $4 $4 $13 $11 $9 $9 $9 $9 $82 EBITDA Margin (%) 23% 10% 12% 12% 15% 14% 37% 35% 33% 33% 33% 34% 25% Memo: Total Operating Expenses $(21) $(19) $(20) $(21) $(23) $(22) $(21) $(20) $(19) $(19) $(18) $(18) $(240) Capex $(8) $(16) $(21) $(5) $(46) $(6) $(1) $(5) $(3) $(3) $(5) $(4) $(125) Adjusted EBITDAX Less Capex $(1) $(14) $(19) $(2) $(42) $(3) $12 $6 $6 $6 $3 $5 $(43) Restructuring & Chapter 11 Fees $(9) $(8) $(9) $(9) $(26) $ --- $ --- $ --- $ --- $ --- $ --- $ --- $(61) Unlevered Cash Flow (after Ch. 11 Fees) $(10) $(22) $(28) $(11) $(68) $(3) $12 $6 $6 $6 $3 $5 $(104) Memo: Catarina Central / East Volumes (Boe/d) (2) 13,137 13,587 12,317 12,350 13,694 15,761 14,295 15,367 14,924 13,728 13,579 12,640 13,779 Memo: COPAS Recovery/(Payment) - 3rd Parties $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.3 $1.4 $1.4 $1.4 $15.7 Memo: COPAS Recovery/(Payment) - UnSub $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $0.4 $4.5

0 5 10 15 20 25 30 35 40 45 2020 2021 2022 2023 2024 MBoe/d Option Preservation Accelerated Completions PDP Option Preservation Case Provides Commodity Price Upside 16 A going concern company best positions the assets for future rebound in commodity prices or monetization Option Preservation vs. PDP Blowdown: 2021E Production ~22% higher 2021E Adjusted EBITDAX ~64% higher Accelerated Completions vs. PDP Blowdown: 2021E Production ~1% higher 2021E Adjusted EBITDAX ~8% higher Note: Assumes strip pricing as of 2/11/20. Option Preservation vs. PDP Blowdown: 2024E Production ~45% higher 2024E Adjusted EBITDAX ~326% higher Accelerated Completions vs. PDP Blowdown: 2024E Production ~36% lower 2024E Adjusted EBITDAX ~287% higher

Immediate steps have been taken to delay capital spend, optimize operations and reduce costs; the Company is focused on key ongoing business initiatives to maximize asset value Asset Development The drilling program at Catarina was thoroughly reviewed, with timing for continued activity pushed approximately one month, from early January to early February 2020; the existing rig was moved from Catarina to Comanche during the first week of Janu ary ; as part of this review, the Company’s drilling schedule was optimized, resulting in an overall lower rig count The revised development plan has been designed to preserve the asset base and maintain optionality while minimizing near - term capital outlay The business plan assumes drilling only economic wells (minimum threshold of 20% IRR (1) ), unless certain wells are required to be drilled to retain a major lease under CDC obligations – if the Accelerated Completions Case were to be adopted, the remaining DU C inventory would be completed with no further development activity in Catarina after June 2020 The Company currently has 3 rigs across the entire asset base (1 at Catarina and 2 at Comanche); however, not all are active In the event that the Company pursues a plan that involves the drilling of additional wells in Catarina, that plan would result in 2 active rigs at Catarina and 1 at Comanche Midstream The SECO midstream contract was terminated on January 13, 2020, with 30 - day notice provided to SNMP Midstream contract optimization opportunities are being evaluated, with consideration of commercial, economic and legal implications Value accretion to both SN and SNMP may be available through the Debtors’ midstream optimization strategy; any value that may be captured by SNMP will be addressed through a comprehensive renegotiation (with the goal of capturing maximum value for SN and providing infill gathering rate certainty in Eastern Catarina) Corporate G&A Non - essential overhead expenses, such as the company ranch participation, have been rejected or eliminated, saving approximately $2MM per annum on a run - rate basis; additional cost savings may be realized in the near - term through ongoing G&A review and contract renegotiation and/or rejection Corporate G&A has been thoroughly reviewed by management, with a proposed plan to reduce overhead expenses from approximately $75MM (~$3.00/Boe) in 2019 to an average of approximately $19MM consolidated G&A after COPAS reimbursement (~$1.50/Boe) from 2021 through 2025 Asset Lease Preservation Catarina: TBD All major leases at Comanche are being reviewed on a case - by - case basis Key Ongoing Business Initiatives 17 Note: (1) IRR calculated at $50 oil/$2.50 gas/$14 NGL price deck.

Key Near Term Operational Decisions (2020) 18 Category Decision Catarina Option Preservation Drill remaining 24 wells required in the 2019 - 2020 lease period – Project Capital: $45.0MM Complete 5 DUCs scheduled in February – Project Capital: $11.8MM completions + $1.3MM infrastructure and non - D&C Complete 18 DUCs scheduled in June – Project Capital: $45.6MM completions + $4.7MM infrastructure and non - D&C Drill required wells for 2020 - 2021 lease term – Source rigs for contract, September 2020 spud for 2 - rig program Leaves 31 DUCs to be completed in 2021 – Project Capital: $66.2MM completions + $8.0MM infrastructure and non - D&C Accelerated Completions Complete 31 DUCs scheduled through June Project Capital: $1.9MM drilling (Feb/Mar 2020 only) + $73.9MM completions + $8.0MM infrastructure and non - D&C Comanche Renegotiate lease in La Bandera/FOGMT – Current lease terms expire in April 2020 Drill required wells for 2020 - 2021 lease terms – Source rigs for contract Renegotiate lease in Maund – Current lease terms expire in March 2021 Midstream/ Marketing TBD Outlined below are key operational decisions over the next 12 months

Potential Risks and Upsides to the Proposed Business Plan 19 Risk/Considerations Commodity Prices Further degradation in commodity prices, realizations or differentials Loss of Comanche Operatorship No longer in control of development plan and capital spend Lose ability to collect COPAS from working interest partners and would have to reimburse new operator Likely lower value in a monetization given lack of control Midstream Rates Interruptible gathering rate on Eastern Catarina could be increased by SNMP Comanche infield gathering rates could increase with cost of service model if volumes significantly decline G&A Plan The proposed reduction in G&A corresponds to a reduction in required drilling operations per the business plan Talent retention may be difficult Potential Upside to Business Plan Forecast Commodity Prices Improvement in commodity prices, realizations or differentials Improved commodity prices would also unlock additional inventory that can be drilled at economic returns Contract Optimization TBD Type Curve Outperformance The Company has outperformed production by ~5% compared to its original 2019 budget Many of the Company’s type curves have been recently refreshed at year - end based on new well data Palmetto If Marathon’s 2020 development test is successful, the Company could participate in future development If Marathon’s tests are not successful, the Company would still participate in cash flow sharing through an Overriding Royalty Interest ( ORRI) election that req uires no capital spend on projects proposed in the first 8 months of a given lease year (1% override that converts to a 17.5% working interest after 1.0x payout) Catarina Lease CDC Relief While unlikely, if landowners are willing to provide near - term relief on drilling requirements, the Company could realize significant value from avoiding uneconomic wells and redirecting budgeted capex dollars towards completion activity

III. Asset Development Plan 20 20

Asset Development Approach and Overview 21 A comprehensive asset development assessment was completed since the last business plan presentation Strategy Previous mandate focused on holding assets together and preventing lease expiration as the primary driving objective Current strategy focuses on economic drilling and preserving optionality in the most cost - effective manner Asset Summary ~435,000 gross (~233,000 net) acres in the Eagle Ford More than half of net acreage is held by production and annual/continuous drilling obligations Diversified, lower decline production from significant PDP base with over 2 ,200 wells (on a gross basis) Catarina Type Curves Catarina type curves were reviewed and refreshed in Q4 2019 with the benefit of an additional 12 months of production history Type curve boundaries adjusted to incorporate similar well performance, rock properties, fluid properties and seismic charact eri stics As a result, significant inventory was lost and others shifted from South Central Catarina to Central Catarina, with no remai nin g legacy South Central locations Comanche Type Curves Utilized recent well performance results with wider well spacing and larger completion designs to refine type curves Identified and incorporated into forecast material changes to some type curves from development plan changes Inventory was reduced as a result of increased well spacing and removal of uneconomic targets/infill locations Inventory Complete refresh of inventory based on current development planning and spacing assumptions Created map layers that tie individual sticks on a map to model and ARIES Drilling and Completion Costs Updated to incorporate lower unit costs (sand and horsepower) and drilling and completion efficiencies (7.5 stages/day) Approximately ~12% - 15% per well savings incorporated into business plan vs. 2019 budgeted costs Engineering and Financial Diligence The Debtor advisors’ engineering team evaluated and performed diligence on the geological and technical aspects of the busine ss plan The Debtor advisors reviewed the cost and expense assumptions for each asset Creditor feedback on development plan is being considered and may be incorporated where appropriate and value maximizing

Catarina Asset Overview *Considers drilling capital on DUC inventory sunk † Dashed lines denote East and Solid lines denote West 5 DUCs Drilled Q418 $10.8MM required to frac AVG 26% IRR * at $50 WTI E35 - E36 (East) 18 DUCs Drilled Q418 - Q319 $47.2 MM required to frac AVG 35% IRR * at $50 WTI A44 - A45 (West) 7 DUCs Drilled Q419 4 Remain to be drilled $32.8 MM required to Finish drilling and Frac AVG 26% IRR * at $50 WTI E37 - E39 (East) 22 Asset Map † † Well Selected to satisfy 120 CDC ~106,000 gross / net acres EF wet gas / condensate window Annual lease term July 1 - June 30 50 - well annual drilling commitment 100% WI and 75% NRI Oil/Gas/NGL: 24%/37%/40% 2019 Production: ~35,000 Boe/d PDP Count: 457 wells Current DUC Inventory: 30 wells Total Planned 2020 Spuds / TTP: □ Option Preservation : 24 wells / 23 wells □ Accelerated Completions : 1 well / 31 wells Lease Summary Rig – Completion Schedule Accelerated Completions Option Preservation *Gross  Activity JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR Drilling Well Count 4 6 6 5 3 Online Well Count 5 10 8 17 14 2020 2021  Activity JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR Drilling Well Count 1 Online Well Count 5 8 18 2020 2021 TC Area Drilled AVG IRR @ $50 Wells CATWSO-A 6 45% 6 CATC-C 5 26% 11 CATW-A 18 20% 29 CATWSO-C 16 12% 45 CATSW-C 6 13% 51 CATNW-C 3 0% 54 CATSC-C - - - CATW-C - - - CATNC-C - - - CATNW-A - - - CATC5 - TIER1 - - - CATC5 - TIER2 - - - CATC5 - TIER3 - - - CATE-B - - - Total 54 Development Plan Asset Level Cash Flow Inventory Analysis TC Area CountWTI for 20% IRRCumulative Wells CATC5 - TIER1 12 $65 12 CATNW-A 16 68 28 CATWSO-C 12 71 40 CATWSO-A 9 74 49 CATNC-C 44 76 93 CATC5 - TIER2 12 76 105 CATNW-C 17 77 122 CATSW-C 35 82 157 CATC-C 28 84 185 CATC5 - TIER3 16 84 201 CATW-A 1 89 202 CATE-B 152 107 354 Total 354 Undeveloped Inventory *Gross ($49) $21 $62 $46 $36 ($300) ($200) ($100) $0 $100 $200 $300 2020 2021 2022 2023 2024 $MM ($12) $53 $42 $35 $28 ($300) ($200) ($100) $0 $100 $200 $300 2020 2021 2022 2023 2024 $MM Revenue ($M) Operating Costs ($M) Sev & Ad Val Tax ($M) Capital ($M) Free Cash Flow ($M) Accelerated Completions Option Preservation

Inventory Analysis ~250,000 gross / ~61,000 net acres EF volatile oil / condensate gas window 23 separate lease commitments ~40 - 60 well per year drilling commitment Average ~24% WI and ~18% NRI; Restricted average ~6% WI and ~4% NRI Oil/Gas/NGL: 37%/30%/33%; Restricted Oil/Gas/NGL: 45%/26%/29% Asset Level Cash Flow (Restricted) 2019 Production: ~28,000 Boe/d Gross PDP Count: 1,738 wells Total Planned 2020 Spuds: 55 wells Total Planned 2020 TTP : 57 wells Comanche Asset Overview *Gross 23 Lease Summary Rig Completion Schedule Asset Map Note: Development plan counts are as of 1/1/20 and Comanche’s maverick type curve area is largely exploratory with no wells o n l ease. Individual wells that appear economic at lower prices are isolated and have certain physical operational hinderances to drilling. TC Area Count WTI for 20% IRR Cumulative Wells AREA 7-1 4 $32 4 AREA-7-2 1 35 5 AREA-3-2 1 45 6 AREA 3-1B 12 51 18 MAVERICK 46 52 64 AREA-3-3S 1 52 65 AREA 3-3 11 56 76 AREA-5-1 11 61 87 CATNW 12 61 99 AREA-5-3 31 62 130 AREA-5-7 6 63 136 AREA-3-3_UEFAC_Gen10 108 67 244 AREA-5-2 37 68 281 AREA-3-1A 5 75 286 AREA-6-1 12 79 298 AREA-2-3 94 82 392 AREA-3-3 14 82 406 AREA-3-1C 22 83 428 AREA-4-2 81 83 509 AREA-4-1 194 86 703 AREA-3-4 38 90 741 AREA-2-1 100 91 841 AREA-2-2 118 93 959 AREA-3-2_UEFB 93 97 1,052 AREA-1 67 99 1,119 AREA-5-4 63 100 1,182 AREA-3-2_UEFB 1 119 1,183 AREA-3-4_UEFAC 282 130 1,465 AREA-3-3_UEFAC_Gen2 217 311 1,682 AREA-3-1B_UEFAC 26 312 1,708 Total 1,708 Undeveloped Inventory Developed Inventory Cumulative TC Area Count AVG IRR @ $50 Wells AREA-3-2 20 52% 20 AREA-5-7 28 52% 48 AREA-3-1B 34 50% 82 AREA-3-1A 41 47% 123 AREA-7-1 40 47% 163 AREA-7-2 33 41% 196 AREA-3-3S 23 40% 219 AREA-3-3 75 37% 294 AREA-4-1 46 33% 340 AREA-5-1 11 27% 351 AREA-3-3_UEFAC_Gen10 21 22% 372 AREA-3-4 41 21% 413 AREA-5-3 9 17% 422 CATNW 5 16% 427 AREA-2-1 7 6% 434 AREA-3-4_UEFAC 4 3% 438 AREA-3-1C 6 2% 444 AREA 1 - - - AREA 2-2 - - - AREA 2-3 - - - AREA-3-1B_UEFAC - - - AREA-3-2_UEFB - - - AREA-3-3_UEFAC_Gen2 - - - AREA 4-2 - - - AREA 5-2 - - - AREA 5-4 - - - AREA 6-1 - - - MAVERICK - - - Total 444 ($21) ($18) ($25) ($7) $6 ($150) ($100) ($50) $0 $50 $100 $150 2020 2021 2022 2023 2024 $MM Revenue ($M) Operating Costs ($M) Sev & Ad Val Tax ($M) Capital ($M) Free Cash Flow ($M) Option Preservation / Accelerated Completions  Activity JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR Drilling Well Count 11 3 2 5 5 3 4 3 6 9 4 7 4 Online Well Count 3 13 3 6 3 1 11 7 3 7 8 18 3 2020 2021

TC Area Target Drilled Avg. IRR @ $50 Count Avg. IRR @ $55 BHM LEF B - - 17 10% BHM 10,000’ LEF B 8 18% 23 18% BHN LEF B - - 27 2% BHS R1 LEF B - - 21 9% BHS R2 LEF B 2 6% 13 6% BHS R3 LEF B - - 11 0% Total 10 112 Development Plan Undeveloped Inventory TTP - ed: May 2019 Barnhart G Pad TTP - ed: November 2019 Barnhart 100 - 103H Spud: February 2020 Complete: Summer 2020 Barnhart 104 - 107H Spud: April 2020 Complete: Summer 2020 Barnhart 108 - 111H Spud : Q3 2020 Complete : Q4 2020 Barnhart 48H 49H Inventory Analysis ~15,500 gross / ~7,500 net acres EF black oil window Annual drilling commitment based on WTI Average 50% WI and 36.35% NRI Oil/Gas/NGL: 69%/15%/16% Asset Level Cash Flow 2019 Production: ~1,000 Boe/d Gross PDP Count: 83 wells Total Planned 2020 Spuds (1) : 10 wells Total Planned 2020 TTP (1) : 10 wells Palmetto Asset Overview 24 Lease Summary Rig Completion Schedule (1) Asset Map (1) Marathon (operator) intends to drill and complete 10 wells in 2020. Due to near term considerations, SN has elected not to pa rti cipate in 8 of 10, without leasehold risk. Remaining elections pending. (2) Represents gross well economics; new money returns on these 8 wells, net of SN’s ORRI, is approximately 25%. $6 $3 $2 $1 $1 ($4) ($2) $0 $2 $4 $6 $8 $10 2020 2021 2022 2023 2024 $MM Revenue ($M) Operating Costs ($M) Sev & Ad Val Tax ($M) Capital ($M) Free Cash Flow ($M)  Activity JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR Drilling Well Count Online Well Count 2020 2021

TC Area Target DevelopmentCountHBPWTI for 20% IRR HAUSSER LEF B 0 5 5 $62 NORTH DIMMIT LEF B 0 55 4 $64 VOTAW LEF B 0 42 29 $66 HOLDSWORTH LEF B 0 50 7 $67 HARGIS LEF B 0 23 23 $73 PETRO PARDS LEF B 0 119 76 $75 Total 294 144 Inventory Summary Inventory Analysis ~62,000 gross / ~40,000 net acres ~24,316 net acres held by production EF volatile oil / black oil 100% WI and 75% NRI Oil/Gas/NGL: 97%/2%/2% Asset Level Cash Flow 2019 Production: ~2,600 Boe/d Gross PDP Count: 79 wells Total Planned 2020 Spuds: 0 wells Total Planned 2020 TTP : 0 wells Maverick Asset Overview 25 Lease Summary Rig Completion Schedule Asset Map Note: Maverick asset is largely exploratory with minimal activity in the last year and type curves would need further risking if considering development. $24 $18 $14 $12 $10 ($15) ($10) ($5) $0 $5 $10 $15 $20 $25 $30 $35 $40 2020 2021 2022 2023 2024 $MM Revenue ($M) Operating Costs ($M) Sev & Ad Val Tax ($M) Capital ($M) Free Cash Flow ($M)  Activity JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC JAN FEB MAR Drilling Well Count Online Well Count 2020 2021

IV. Midstream 26 26

Illustrative Catarina Marketing Diagram 27 Terminated Jan 2020 Wellhead Gathering Gas Processing Catarina Midstream Gas Gathering, Processing & NGL Purchase Transportation Gas Gathering, Processing & NGL Purchase Wellhead Residue Markets Gas Marketing Oil Marketing Wellhead Gathering Oil Stabilization Catarina Midstream Stabilization & NGL Purchase Gathering Oil Transportation Wellhead Residue Markets Residue Markets Oil Markets Condensate Markets Sales Sales Transportation SECO Diagrams below represent the flow of hydrocarbons from Catarina

Illustrative Comanche Marketing Diagram 28 Diagrams below represent the flow of hydrocarbons from Comanche Wellhead Gathering Gas Processing Gas Gathering Transportation Wellhead Residue Markets Gas Marketing Wellhead Gathering Oil Stabilization Oil Gathering Stabilization & NGL Purchase Gathering Oil Transportation Wellhead Residue Markets Residue Markets Oil Markets Pipeline Sales Sales Transportation SECO Residue Markets Transportation NGL Purchase Transportation Gas Gathering, Processing & NGL Purchase Gas Processing & Stabilization Gas Gathering, Processing & NGL Purchase Gathering Stabilization & NGL Purchase Oil Markets (Drip Condensate) Sales FOGMT Gas Gathering Terminated Jan 2020 R* R* R* R* R* Identifies the agreements subject to either the Retained Marketing Contracts Services Agreement or the Retained Midstream Contracts Services Agreement, between SN EF Maverick, LLC, SN Catarina, LLC, Anadarko E&P Onshore LLC, Kerr - McGee Oil & Gas Onshore LP and Anadarko Energy Services Company, as referenced in the Purchase and Sale Agreement between certain of such parties dated as of January 12, 2017. Oil Marketing R*

V. Corporate G&A 29 29

COPAS Overview 30 General Summary The Council of Petroleum Accountants Societies (COPAS) is a non - profit professional organization established in 1961 that outl ines accounting guidelines and practices within the North American petroleum industry Base overhead rates that an operator can charge out to working interest partners must be agreed upon in the various Joint Ope rat ing Agreements (JOA) between SN and its various counterparties. However, COPAS accounting procedures provide for the annual adjustment of the fixed rate overhead for drilling and producing wells COPAS does not publish or recommend any specific overhead rates or overhead surveys, as the rates are derived through negotia tio n among the parties to an agreement COPAS at SN COPAS in Business Plan Model The business plan forecast calculates the average of the last 10 years of rate adjustments released by COPAS, which is approx ima tely 3% The current average amount that SN is able to charge out to working interest partners is $950 per well, each month Beginning with the $950 monthly rate per well, the model assumes that the chargeable rate will increase at ~3% annually, as i n t he last ten years In a blowdown scenario where SN gives up operatorship, SN would then incur an additional expense per the JOA, instead of a re cei pt JOAs that SN is party to are subject to the adjustment rates that COPAS releases on an annual basis With SN being the operator of the Comanche assets, SN is able to charge the other working interest partners monthly The amounts that SN can charge out to working interest parties depend entirely on the well count, irrespective of changes in the Company’s expenses A charge to the Company’s working interest partners is reflected as a credit to G&A on SN’s books and records

Appendix 31 31

A. PDP Reference Case 32 32

PDP Reference Case: Historical and Financial Projections (Accrual) 33 Notes: Represents consolidated cash flow forecast net to Debtors. Presented on an accrual basis. Strip pricing as of 2/11/20 . (1) Q4 2019 quarter actuals are estimates and subject to change upon finalized earnings. (2) Represents non - cash, non - recurring and other amounts included in the above line items which are traditionally added back or excluded in the determination of Adjusted EBITDAX. The amount primarily reflects restructuring fees and certain non - cash adjustments . (3) Production volumes from ARIES database may not tie exactly to the company model. Pre- Emergence Post- Emergence Jan-May Jun-Dec Full Year $ millions 2017A 2018A 2019E (1) 2020E 2020E 2020E 2021E 2022E 2023E 2024E Oil (Boe/d) 15,085 18,026 14,949 11,374 12,941 12,259 9,724 7,243 5,958 5,125 Gas (Mcf/d) 104,638 105,400 89,143 72,109 79,748 76,379 63,919 50,995 43,261 37,926 NGL (Boe/d) 15,171 18,762 15,829 13,511 14,916 14,296 11,999 9,562 8,105 7,101 Total Net Daily Production (Boe/d) 47,695 54,355 45,635 36,903 41,149 39,285 32,376 25,304 21,273 18,547 Benchmark Commodity Prices: WTI ($/Bbl) $50.97 $64.66 $57.02 $51.65 $51.00 $51.27 $50.89 $50.96 $51.32 $51.69 Henry Hub ($/Mcf) $3.11 $3.11 $2.60 $1.87 $2.13 $2.02 $2.36 $2.41 $2.45 $2.47 Mt. Belvieu Propane ($/Bbl) $20.48 $23.45 $22.46 $16.36 $17.86 $17.24 $18.45 $18.93 $19.30 $19.43 Realized Commodity Prices: Oil ($/Bbl) $49.47 $65.73 $56.34 $49.48 $48.55 $48.90 $48.64 $48.68 $49.00 $49.35 Gas ($/Mcf) $3.17 $3.14 $2.67 $1.85 $2.11 $2.01 $2.34 $2.39 $2.43 $2.45 NGL ($/Bbl) $21.10 $23.39 $14.09 $8.33 $9.10 $8.80 $9.34 $9.60 $9.80 $9.88 Oil Revenue $272 $432 $307 $85 $134 $219 $173 $129 $107 $93 Gas Revenue 121 121 87 20 36 56 55 45 38 34 NGL Revenue 117 160 81 17 29 46 41 34 29 26 Other Sales and Marketing Revenue --- 26 18 --- --- --- --- --- --- --- Oil, Gas, & NGL Revenue $510 $739 $494 $122 $199 $322 $268 $207 $174 $152 Hedge Gain / (Loss) $5 $(86) $8 $ --- $ --- $ --- $ --- $ --- $ --- $ --- Other Sales and Marketing Expenses --- (24) (17) --- --- --- --- --- --- --- Lease Operating Expenses (49) (64) (43) (13) (19) (32) (30) (29) (27) (27) Marketing (108) (131) (160) (58) (91) (149) (131) (108) (89) (78) Production Taxes (18) (30) (18) (5) (8) (13) (11) (8) (7) (6) Ad Valorem Taxes (5) (10) (10) (3) (4) (7) (6) (4) (4) (3) Corporate G&A (114) (87) (89) (26) (25) (51) (17) (17) (18) (18) Restructuring & Chapter 11 Fees --- --- (83) (61) --- (61) --- --- --- --- Total G&A (114) (87) (173) (86) (25) (111) (17) (17) (18) (18) Reconciling Items to EBITDAX (2) 28 (6) 87 61 --- 61 --- --- --- --- Adjusted EBITDAX $249 $302 $167 $18 $52 $70 $74 $40 $29 $20 EBITDA Margin (%) 49% 41% 34% 15% 26% 22% 27% 19% 17% 13% Memo: Total Operating Expenses $(261) $(437) $(327) $(104) $(148) $(252) $(194) $(167) $(145) $(132) Capex $(485) $(512) $(62) $(97) $(27) $(124) $(12) $(1) $(1) $(1) Adjusted EBITDAX Less Capex $(236) $(210) $105 $(79) $25 $(54) $62 $39 $28 $19 Restructuring & Chapter 11 Fees $ --- $ --- $(83) $(61) $ --- $(61) $ --- $ --- $ --- $ --- Unlevered Cash Flow (after Ch. 11 Fees) $(236) $(210) $21 $(139) $25 $(115) $62 $39 $28 $19 Memo: Catarina Central / East Volumes (Boe/d) (3) 13,779 10,754 8,431 7,073 6,127 Memo: COPAS Recovery/(Payment) - 3rd Parties $11 $19 $16 $6 $(1) $5 $(5) $(5) $(6) $(6) Memo: COPAS Recovery/(Payment) - UnSub $2 $4 $4 $2 $3 $4 $5 $5 $5 $5

B. Other Supporting Items 34 34

35 Historical EBITDAX Reconciliation Restricted Group (1) Represent non - cash adjustments to net income . (2) Includes cash received and non - cash (gains) losses. 2017 2018 (In Thousands) Consolidated SN Restricted Group (Model) Consolidated SN Restricted Group (Model) FY FY FY FY Adjusted EBITDAX: Net income (loss) $ 43,191 $ (6,851) $ 85,205 $ (22,501) Adjusted by: Interest expense 128,189 120,550 165,233 156,398 Amortization of debt costs (1) 11,975 8,880 12,625 8,819 Net losses (gains) on commodity derivative contracts (2) 6,099 7,986 27,756 32,316 Net settlements paid on commodity derivative contracts 13,140 670 (103,205) (81,141) Exploration expense 5,755 5,755 3,295 3,284 Depreciation, depletion, amortization and accretion (1) 177,153 125,696 262,481 197,388 Impairment of oil and natural gas properties (1) 39,499 39,499 14,386 14,337 Stock - based compensation (1) 22,909 22,909 792 792 Acquisition and divestiture costs included in G&A 30,526 30,334 778 778 Income tax expense (benefit) (2,336) (2,336) - - Gains on sale of oil and natural gas properties - - (1,528) (1,528) Gains on disposal of assets (81,955) (81,955) - - Loss on impairment of other assets - - - - Impairment of right of use assets - - - - Accrued amount for executive bonuses included in G&A - - - - (Gains) losses on embedded derivatives 1,551 1,551 (700) (700) (Gains) losses on investments 871 871 21,798 21,798 Amortization of deferred gain on Catarina Midstream sale (23,718) (23,718) (23,720) (23,720) Interest income (836) (836) (4,351) (4,351) Adjusted EBITDAX $ 372,013 $ 249,004 $ 460,845 $ 301,969

Pricing (As of 2/11/20) Commodity Price Realizations Differentials have been developed by asset area based on historical 12 - month average as compared to current futures pricing and relevant contract changes. Lease Operating Expense G&A 36 Strip 2020 2021 2022 2023 2024 WTI Oil ($/Bbl) $51.27 $50.89 $50.96 $51.32 $51.69 Henry Hub Gas ($/MMBtu) $2.02 $2.36 $2.41 $2.45 $2.47 Mt. Belvieu Propane ($/Bbl) $17.24 $18.45 $18.93 $19.30 $19.43 Realizations Catarina Comanche Maverick Palmetto OBO SR TMS Oil (% WTI) 93% 98% 99% 105% 103% 109% 105% Gas (% Henry Hub) 99% 100% 100% 103% 62% 100% 100% NGL (% Mt B Propane) 52% 43% 69% 63% 62% - - Business Plan Assumptions (Option Preservation Case) Note: Strip pricing sourced from Capital IQ as of 2/11/20. TBU $2.37 $2.19 $2.58 $2.83 $2.95 $9.73 $9.07 $9.09 $8.88 $8.65 $0.98 $0.98 $1.27 $1.04 $0.73 $13.09 $12.24 $12.93 $12.75 $12.33 2020 2021 2022 2023 2024 $ / Boe LOE Marketing Deficiencies $38 $15 $15 $14 $14 2020 2021 2022 2023 2024 $MM

Drilling Activity (SPUD) 37 Completion Activity (TTP) Business Plan Assumptions (Option Preservation Case) 23 31 57 59 54 75 82 80 90 54 75 82 2020 2021 2022 2023 2024 Gross Wells Catarina Comanche Other 24 55 67 77 53 66 79 67 77 53 66 2020 2021 2022 2023 2024 Gross Wells Catarina Comanche Other

Capital Expenditures ` Well Costs (1) 38 Business Plan Assumptions (Option Preservation Case) $1.6 $1.5 $1.5 $1.7 $1.9 $2.4 $2.4 $3.3 $0.3 $0.5 $0.5 $0.8 $3.9 $4.3 $4.4 $5.8 Catarina Comanche Maverick Palmetto $MM Drilling Completion Facilities & Lift Note: (1) Presented well costs are based on an average 6,000 ft lateral, but each well is adjusted based off its exact lateral length i n a ll financial forecasts. $108 $74 $40 $37 $49 $46 $46 $1 $1 $1 $1 $1 $149 $113 $50 $47 $47 $0 $20 $40 $60 $80 $100 $120 $140 $160 2020 2021 2022 2023 2024 $ MM Catarina Comanche Non D&C/Other

Pricing (As of 2/11/20) Commodity Price Realizations Differentials have been developed by asset area based on historical 12 - month average as compared to current futures pricing and relevant contract changes. Lease Operating Expense G&A 39 Realizations Catarina Comanche Maverick Palmetto OBO SR TMS Oil (% WTI) 93% 98% 99% 105% 103% 109% 105% Gas (% Henry Hub) 99% 100% 100% 103% 62% 100% 100% NGL (% Mt B Propane) 52% 43% 69% 63% 62% - - Business Plan Assumptions (Accelerated Completions Case) Note: Strip pricing sourced from Capital IQ as of 2/11/20. $2.26 $2.54 $2.84 $3.03 $3.11 $9.47 $9.79 $9.37 $8.89 $8.62 $0.92 $1.18 $1.44 $1.13 $0.78 $12.64 $13.51 $13.64 $13.05 $12.51 2020 2021 2022 2023 2024 $ / Boe LOE Marketing Deficiencies $38 $15 $15 $14 $14 2020 2021 2022 2023 2024 $MM Strip 2020 2021 2022 2023 2024 WTI Oil ($/Bbl) $51.27 $50.89 $50.96 $51.32 $51.69 Henry Hub Gas ($/MMBtu) $2.02 $2.36 $2.41 $2.45 $2.47 Mt. Belvieu Propane ($/Bbl) $17.24 $18.45 $18.93 $19.30 $19.43

Drilling Activity (SPUD) 40 Completion Activity (TTP) Business Plan Assumptions (Accelerated Completions Case) 1 55 67 77 53 66 56 67 77 53 66 2020 2021 2022 2023 2024 Gross Wells Catarina Comanche Other 31 57 59 54 75 82 88 59 54 75 82 2020 2021 2022 2023 2024 Gross Wells Catarina Comanche Other Note: In comparison, PDP reference case drilling and completion activity is comprised of the following: Drilling 1 well in Cat arina (2020), 66 wells in Comanche (55 in 2020 and 11 in 2021), Completions - 31 wells in Catarina (all in 2020), 80 wells in Comanche (57 in 2020 and 23 in 2021)

Capital Expenditures ` Well Costs (1) 41 Business Plan Assumptions (Accelerated Completions Case) $1.6 $1.5 $1.5 $1.7 $1.9 $2.4 $2.4 $3.3 $0.3 $0.5 $0.5 $0.8 $3.9 $4.3 $4.4 $5.8 Catarina Comanche Maverick Palmetto $MM Drilling Completion Facilities & Lift Note: (1) Presented well costs are based on an average 6,000 ft lateral, but each well is adjusted based off its exact lateral length i n a ll financial forecasts. $84 $0 $40 $37 $49 $46 $46 $1 $1 $1 $1 $1 $125 $38 $50 $47 $47 $0 $20 $40 $60 $80 $100 $120 $140 2020 2021 2022 2023 2024 $ MM Catarina Comanche Non D&C/Other

$(100) $(75) $(50) $(25) $0 $25 $50 $75 $100 $125 $150 Dec 27 2019 Jan 17 2020 Feb 7 2020 Feb 28 2020 Mar 20 2020 Apr 10 2020 May 1 2020 May 22 2020 Jun 12 2020 Jul 3 2020 Jul 24 2020 Aug 14 2020 Sep 4 2020 Sep 25 2020 Oct 16 2020 Nov 6 2020 $ Millions Option Preservation Accelerated Completion PDP Reference Liquidity at 5/31: Option Preservation: $24.0 MM Accelerated Completion: $27.9 MM PDP Reference: $27.4 MM Minimum Cash: $15mm Liquidity at 8/14: Option Preservation: ($26.7) MM Accelerated Completion: ($23.4) MM PDP Reference: ($23.8) MM Forecast Liquidity 42 Similar Liquidity Profile at Exit in Option Preservation, Accelerated Completions, and PDP Reference Scenarios Liquidity at 5/31/2020 of $24.0MM in the Option Preservation scenario, $27.9MM in the Accelerated Completion scenario, and $2 7.4 MM in a PDP Reference scenario. Cash Flows include: □ Payment of accrued DIP interest at 5/31/2020 and exit fees of 1.5% of total new money commitment (~$1.8MM) □ 1L adequate protection paid during case ($36MM) and accrued adequate protection paid on 5/31/2020 ($9.4MM) □ Payment of all accrued & unpaid professional fees and success fees (~38.3MM) DIP commitment is $150MM of new money and $50MM of 1 st lien roll - up to be refinanced upon exit No additional disbursements associated with emergence are included in this forecast *PDP Reference scenario does not assume full conversion to non - operated cash based forecast

Sanchez Energy Organizational Structure (Pre - Petition) 43 Unrestricted Subsidiary Restricted Subsidiary (Guarantor of SN Credit Agreement & Senior Notes) Sanchez Oil & Gas Corporation (SOG) Other Sanchez Group Public SN Capital, LLC SR TMS, LLC SR Acquisition III, LLC SR Acquisition I, LLC 100% 100% 100% 100% 100% 100% SN Marquis LLC SN Cotulla Assets, LLC SN Palmetto, LLC SN Operating, LLC SN TMS, LLC SN Catarina, LLC SN Payables, LLC Rockin L Ranch Company, LLC 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% SN Services, LLC SN Terminal, LLC SN Midstream, LLC SN Comanche Manager, LLC SN EF UnSub GP, LLC SN EF UnSub Holdings, LLC $500MM non - recourse revolving credit facility 100% preferred 100% of acquisition PDP & 40% of development thereafter 100% common 100% non - economic GP interest 60% of development post - acquisition SN EF UnSub, LP $24MM non - recourse credit facility $4.25MM secured non - recourse 4.59% term loan SN UR Holdings, LLC Comanche Assets (SN’s Net ~25% WI) 99% (99 Class A Units) 1% (1 Class B Unit) 2,272,727 Common Units Sanchez Resources, LLC SN Debt / Preferred Equity $25MM first - out senior secured working capital and letter of credit facility $500MM of 7.25% Senior Secured Notes due 2023 $600MM of 7.75% Senior Notes due 2021 $1.15B of 6.125% Senior Notes due 2023 $60.1MM of 4.875% Series A Preferred Stock $125.6MM of 6.500% Series B Preferred Stock Issuer SN EF Maverick, LLC 100% 100% Sanchez Midstream Partners LP (SNMP) Unrestricted Subsidiary Restricted Subsidiary (Guarantor of SN Credit Agreement & Senior Notes) GSO Capital Partners LP (1) Services Agreement Sanchez Energy Corporation (SN) Notes: (1) 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 Priva te Equity SPV - A, L.P.

Comanche Ownership Structure 44 Comanche Restricted Comanche ~15% UnSub Comanche ~10% Gavilan (Blackstone) ~25% KNOC ~25% Venado (KKR) ~12.5% Mitsui ~12.5% Sanchez Energy Corporation Catarina 100% Maverick 100% Palmetto ~50% Note: Percentages shown represent interest in future development .

Annual NYMEX WTI Oil Strip Pricing 45 Annual Averages 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Strip as of 11/30/2019 $53.86 $51.26 $50.24 $50.07 $50.30 $50.79 $51.09 $51.24 $51.20 $51.20 $51.20 Strip as of 12/15/2019 $58.05 $53.99 $51.92 $51.16 $51.08 $51.32 $51.52 $51.62 $51.58 $51.58 $51.58 Strip as of 12/31/2019 $58.83 $54.38 $52.09 $51.31 $51.44 $52.07 $52.57 $52.84 $52.84 $52.84 $52.84 Strip as of 1/15/2020 $56.71 $53.33 $51.57 $51.01 $51.15 $51.66 $52.09 $52.34 $52.36 $52.36 $52.36 Strip as of 2/11/2020 $50.76 $50.89 $50.96 $51.32 $51.69 $52.04 $52.22 $52.38 $52.40 $52.40 $52.40 $50.0 $52.5 $55.0 $57.5 $60.0 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Price ($ / Bbl) Strip as of 11/30/2019 Strip as of 12/15/2019 Strip as of 12/31/2019 Strip as of 1/15/2020 Strip as of 2/11/2020

Annual Averages 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Strip as of 11/30/2019 $2.27 $2.41 $2.44 $2.48 $2.54 $2.58 $2.63 $2.72 $2.80 $2.91 $3.01 Strip as of 12/15/2019 $2.29 $2.45 $2.45 $2.48 $2.52 $2.57 $2.61 $2.69 $2.75 $2.84 $2.92 Strip as of 12/31/2019 $2.29 $2.42 $2.42 $2.46 $2.49 $2.53 $2.55 $2.60 $2.65 $2.69 $2.75 Strip as of 1/15/2020 $2.25 $2.43 $2.44 $2.47 $2.51 $2.55 $2.57 $2.63 $2.67 $2.71 $2.77 Strip as of 2/11/2020 $2.04 $2.36 $2.41 $2.45 $2.47 $2.49 $2.49 $2.52 $2.55 $2.59 $2.65 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Price ($ / MBtu) Strip as of 11/30/2019 Strip as of 12/15/2019 Strip as of 12/31/2019 Strip as of 1/15/2020 Strip as of 2/11/2020 Annual NYMEX Henry Hub Gas Strip Pricing 46

Annual Mt. Belvieu Propane Strip Pricing 47 Annual Averages 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Strip as of 11/30/2019 $21.35 $21.31 $21.75 $22.13 $22.27 $22.79 $22.79 $22.79 $22.79 $22.79 $22.79 Strip as of 12/15/2019 $21.57 $22.15 $22.62 $22.97 $23.11 $23.63 $23.63 $23.63 $23.63 $23.63 $23.63 Strip as of 12/31/2019 $19.04 $20.16 $20.86 $21.24 $21.38 $21.89 $21.89 $21.89 $21.89 $21.89 $21.89 Strip as of 1/15/2020 $19.40 $20.45 $20.86 $21.24 $21.38 $21.27 $21.79 $21.79 $21.79 $21.79 $21.79 Strip as of 2/11/2020 $17.26 $18.39 $18.85 $19.27 $19.43 $19.35 $19.41 $19.33 $19.33 $19.33 $19.33 $15.0 $18.0 $21.0 $24.0 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Price ($ / Bbl) Strip as of 11/30/2019 Strip as of 12/15/2019 Strip as of 12/31/2019 Strip as of 1/15/2020 Strip as of 2/11/2020