May 2016 VK 989 - Pompano Stone Energy Corporation – Presentation to Noteholders PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT

2 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Disclaimer None of Stone Energy Corporation (“Stone” or the “Company”), Lazard and Alvarez & Marsal Holdings, LLC (“A&M”), and each of their subsidiaries, affiliates, officers, directors, shareholders, employees, consultants, advisors, agents and representatives of the foregoing (collectively, “Representatives”), make any representation or warranty, express or implied at law or in equity, in connection with any of the information made available either herein or subsequent to this document, including, but not limited to, the past, present, or future value of the anticipated cash flows, income, costs, expenses, liabilities and profits, if any, of the Company. Accordingly, any person, company or interested party will rely solely upon its own independent examination and assessment of the information in making any decision in connection with a proposed restructuring of the Company’s balance sheet (a “Transaction”) and in no event shall any recipient party make any claim against Stone, Lazard, A&M or any of their respective Representatives in respect of, or based upon, the information contained either herein or subsequent to this document. None of Stone, Lazard or A&M, nor any of their respective Representatives, shall have any liability to any recipient party or its respective Representatives as a result of receiving and/or evaluating any information concerning the Transaction (including, but not limited to, this presentation (“Presentation”)). This Presentation is being made to you on a confidential basis in accordance with the terms of the non-disclosure agreement (the “NDA”) entered into between the recipient and Stone. This Presentation and the information contained herein may only be used by the recipient as provided in the NDA. Information in this Presentation with respect to Executive Summary, Asset Overview and Operations Update, Gulf of Mexico and Appalachia, Business Plan Overview and Long-Term Forecast, and Appendix is dependent upon assumptions with respect to commodity prices, production, development capital, exploration capital, operating expenses, availability and cost of adequate capital and performance as set forth in this Presentation. Certain statements in this presentation are forward-looking and are based upon the Company’s current belief as to the outcome and timing of future events. All statements, other than statements of historical facts, that address activities that Stone plans, expects, believes, projects, estimates or anticipates will, should or may occur in the future, including anticipated cash flows, income, costs, liabilities, profits, future production of oil and gas, future capital expenditures and drilling of wells and future financial or operating results are forward-looking statements. All forward-looking numbers are approximate. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include the timing and extent of changes in commodity prices for oil and gas, operating risks, liquidity risks (including risks related to our bank credit facility, our outstanding notes and the restructuring thereof and our ability to continue as a going concern), political and regulatory developments and legislation, including developments and legislation relating to our operations in the Gulf of Mexico and Appalachia, and other risk factors and known trends and uncertainties as described in Stone’s Annual Report on Form 10-K for the year ended December 31, 2015 (“2015 Form 10-K”) and Stone’s Quarterly Report on Form 10-Q for the three months ended March 31, 2016, and Stone’s Current Reports on Form 8-K, each as filed with the Securities and Exchange Commission (the “SEC”). Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Stone’s actual results and plans could differ materially from those expressed in the forward-looking statements. Estimates for Stone’s future production volumes and reserves are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, hurricanes and numerous other factors. Stone’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. The recipient hereby acknowledges that none of Stone, Lazard, A&M or any of their Representatives has an obligation to update any such projections or forecasts. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions of such terms. Stone discloses only estimated proved reserves in its filings with the SEC. Stone's estimated proved, probable and possible reserves as of December 31, 2015 contained in this presentation were prepared by Netherland, Sewell & Associates, Inc., a nationally recognized engineering firm, and comply with definitions promulgated by the SEC. Additional information on Stone's estimated proved reserves is contained in the 2015 Form 10-K. In this presentation, we use the terms “estimated ultimate recovery,” “EUR” or other descriptions of volumes of resources potentially recoverable through additional exploratory drilling or recovery techniques, which volumes the SEC's guidelines may prohibit Stone from including in filings with the SEC. These estimates, as well as estimates of probable and possible reserves, are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being actually realized by Stone. “EUR” refers to Stone's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. “EURs” do not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System. Actual quantities that may be ultimately recovered from Stone's interests might differ substantially. Factors affecting ultimate recovery include the scope of Stone’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, changes in law and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. EURs may change significantly as development of our resource plays provides additional data.

3 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Stone Energy Executive Team Is Highly Experienced Kenneth H. Beer Executive Vice President Chief Financial Officer Dartmouth, Stanford MBA Keith A. Seilhan Senior Vice President Gulf of Mexico LSU, MIT, Stanford Lisa S. Jaubert Senior Vice President General Counsel & Secretary UVa, Tulane Law John J. Leonard Senior Vice President Exploration USNA, UL, Harvard AMP Tom L. Messonnier Vice President Planning, Marketing & Midstream LSU, Tulane MBA David H. Welch Stone Energy Corporation Chairman, President and Chief Executive Officer LSU, Tulane Doctoral, Harvard Florence M. Ziegler Senior Vice President Human Resources UL HR, MBA E.J. Louviere Senior Vice President Land LSU, Loyola Law Richard L. Toothman Jr. Senior Vice President Appalachia WVU, Harvard AMP

4 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Agenda  Executive Summary  Asset Overview and Operations Update Gulf of Mexico Appalachia  Business Plan Overview and Long-Term Forecast  Appendix

5 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Stone Energy Investment Opportunity Near Term Focus  Deep water Development to Maintain Production and Cash Flow  Deep water Exploration to Grow Company  Manage Appalachia Acreage Position to Maintain Development Exposure Provides Access to Optionality  Oil Price – GoM Base Production and Exploration Success  Gas Price –Appalachia Reserves and Revenue  Lamprey – High Potential Exploration Prospect  Acquisitions – Operational and Infrastructure Leverage

6 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Stone is Focused in Lowest Cost North American Basins Source: Wood Mackenzie as of March 2016. (1) Gulf of Mexico breakeven prices in US$/bbl Brent adjusted down $2.0 to conform to WTI pricing. Excludes Lower Tertiary Plays. SW Marcellus & Utica Deep water GoM Marcellus - West Virginia Marcellus - Southwest PA Haynesville & CV $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 0 50,000 100,000 150,000 200,000 250,000 H e n ry H u b b re ak e ve n at 10 % IR R ( U S$ /m cf ) Cumulative undrilled commercial gas resource (bcf) Utica Marcellus - Northeast PA Deep Water(1) Wolfcamp Eagle Ford Niobrara Bone Spring Mid - Con Bakken Three Forks 0 10 20 30 40 50 60 70 80 90 $100 0 5,000 10,000 15,000 20,000 25,000 30,000 WTI b re ak e ve n at 10 % IR R ( U S$ /b b l) Cumulative undrilled commercial liquids resource (mmbbl) Stone Focus Area

7 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Stone Energy Company Highlights and Overview Stone Energy IPO 1993 Headquarters: Lafayette, Louisiana Employees: 308 Core Assets Gulf of Mexico • March 2016 production of 30 Mboepd • LOE driven down to $4.85/boe at Pompano (includes revenue from production handling agreements) • Pompano growth driven by development of the Cardona and Amethyst tie-backs • Planned 2017 Pompano development drilling program • Numerous subsea tie back opportunities • High Potential exploration Lamprey prospect Appalachia • Expanded into Appalachia in 2006 through leasehold acquisitions • 27 existing well pads and 7 engineered well pads support 210 gross other identified drilling locations • Significant portion of core WV wet-gas Marcellus and dry-gas Utica now HBP • Averaged 130 mmcfepd net prior to shutting in the Mary field on September 1, 2015 45% 6%8% 5% 24% 1% 11% MARY HEATHER BUDDY TANNER CHRISTINE JOSIE ANDIE Appalachia Pompano Amberjack Lamprey Derbio Audubon Apple Legend Business Plan Prospect Rialto Kuskulana MP 288 Horned Lark Cardona Rampart Luling Banyan Ship Shoal 113 Gulf of Mexico Marcellus Net Acreage Inventory by Prospect (88,677 net acres) • 110 Deep water leases • 11 High potential prospects • 15 Tie-back exploration projects • 10 Platform development wells SGY SGY $0 $5 $10 $15 $20 0 5 10 15 20 25 30 2014 2015 2016 Est LO E/ B O E P ro d u ct io n M B O EP D Production and Unit LOE GOM SF LOE/BOE Antero Eclipse Rice Exxon/XTO Consol/Noble MHR Range CHK/Statoil Chevron SGY SGY

8 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Capital Spend and Expenses Proactively Reduced $MM $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2013 2014 2015 Est. 2016 $695 $895 $468 Capital Expense $169 $0 $50 $100 $150 $200 $250 2013 2014 2015 Est. 2016 $201 $176 $100 LOE+MM$MM $88 $60 $70 $80 $90 $100 $110 $120 2013 2014 2015 Est. 2016 $MM $100 $111 $107 SG&A $88 Net Capital Reduced 81% LOE Reduced 50% SG&A Reduced 21% 2014 – 2016E (1, 2) (1) Capital expense excludes capitalized interest and SG&A, includes ARO (2) 2016 estimates differ from the Company’s publically disclosed guidance and assume completion of the updated baseline case set forth in this Presentation (3) Excludes $3 million in estimated 2016 severance costs (2) (2, 3)

9 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Staff Significantly Reduced 0 100 200 300 400 500 600 700 800 900 2013 2014 2015 Headcount Full Time Office Full Time Field CT Office CT Field 0 10 20 30 40 50 60 70 80 2013 2014 2015 Salaries Full Time Office Full Time Field CT Office CT Field $MM 2014-2015 Reduction Impact Including Contractors • 44% Workforce reduction (23% SGY) • 20% Reduction in salaries • 20% Reduction in field (LOE)

10 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Key Investment Highlights High Quality Asset Base • High quality asset base focused on developing operated exploration and production properties in the deep water Gulf of Mexico • Supplemented by core position in the wet-gas Marcellus and dry gas Utica plays in West Virginia • Recent production of 30 Mboe/d, 66% oil, anchored by operated Pompano and Amberjack fields Extensive GoM Drilling Inventory • Deep exploration portfolio with over 11 high-potential prospects and 15 additional tie-back opportunities • Per Wood Mackenzie, the GoM Deepwater presents the lowest cost of supply oil play in North America Significant Technical Expertise • Currently operate two hub developments (Pompano and Amberjack) in the GoM • Operational capability to develop additional hubs • Large seismic inventory actively managed by experienced technical team Strategic Appalachia Platform • Significant other identified Marcellus/Utica drilling locations in the Mary and Heather fields • Extensive supporting infrastructure in place • Utica development held by production under existing Marcellus producing units • Ability to ramp up production quickly by completing 25 drilled, uncompleted wells Experienced Management Team with Regional Expertise • Balance of experience and innovation • GoM and Appalachian basin-focused team • Experienced and successful deep water operator • Demonstrated ability to move up learning curve in rapidly changing environment

11 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Agenda  Executive Summary  Asset Overview and Operations Update Gulf of Mexico Appalachia  Business Plan Overview and Long-Term Forecast  Appendix

12 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Focus Shifted to Deep Water in Gulf of Mexico • Better exploration risk reward envelope • Built deep water operational capabilities Logical transition from shelf Focused on reducing costs Optimizing infrastructure Responsible P&A management • Built exploration capabilities Experienced deep water geoscientists Significant seismic dataset Acquired leasehold over time Lafayette New Orleans Pompano Amberjack Ship Shoal 113 MP 288 Cardona Amethyst 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 2010 2011 2012 2013 2014 2015 Est. 2016 % o f P ro d u ct io n Offshore Production Deepwater Convention Shelf

13 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Gulf of Mexico Operator with Outstanding Safety Record People ProcessesFacilities Stop Work Authority Safety Observation Program Production Operations Drilling & Completions Major Projects Engineering Construction HSER PSCM Fi re Su p p re ss io n In ci d en t C o m m an d S ys te m Em er ge n cy R es p o n se P la n s Eg re ss R o u te s Em er ge n cy A la rm s & C o m m u n ic at io n s Se co n d ar y C o n ta in m en t Eq u ip m en t R el ia b ili ty (R o ta ti n g & S ta ti c) O p er at in g P ro ce d u re s (S SO P ) C ri ti ca l E q u ip m en t M o n it o ri n g & T es ti n g Q u al it y M an ag em en t Sy st em O p er at o r Tr ai n in g P h ys ic al P la n t I n te gr it y (S tr u ct u ra l,P ro ce ss ,e tc ) Sa fe ty D ev ic es & Equ ip m en t (P P E) Sa fe ty D ri lls Fr o n t- En d E n gi n ee ri n g & D es ig n (F EE D ) H az ar d A n al ys is & H u m an Fa ct o rs C h em ic al M an ag em en t (C o rr o si o n, F lo w A ss u ra n ce ) Sa fe ty & En vi ro n m en ta l M an ag em en t S ys te m ( SE M S) Threat Reduction Impact Minimization Undesired Event Bureau of Safety & Environment National Ocean Industries Association U.S. Coast Guard  Before event reduce threat  During event reduce severity  Post event minimize impact

14 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT • INC free annual inspections – 2013, 2014 & 2015 • Technical development to operate SS tie-back systems Currently operate (5) on Pompano • Enhanced the overall platform integrity (see pics) • Management of SimOps with no major incidents since taking operatorship in 2012 Before After • Operational efficiency of over 94% uptime • Good operating synergies with MC109, VK989 & MP288 • Both Amberjack and Pompano have INC/component ratios below industry average Stone Energy is an Experienced, Successful Deep Water Operator Stone has nine years of deep water operatorship • During that time, the company has established two 100% WI production hubs at Pompano and Amberjack • Provides low cost infrastructure that enables development of subsea tie-backs (SSTBs) • Evidenced by Cardona (multi well) and Amethyst developments • Significant ullage remaining at existing hubs

15 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Operational Track Record with BSEE and BOEM 88 49 42 40 38 31 29 26 23 16 -413 -7 -70 -90 -22 -81 -19 -28 -7 -5 Competitor A Competitor B Competitor C Competitor D Competitor E Competitor F Competitor G Competitor H Competitor I Stone Energy Idle Structures Idle Wells Top Ten Gulf of Mexico Operators by Assets Source: ESA GOMSmart Idle Iron Data Set 2016 • Minimal future idle wells and structures relative to peers • Significant 2011-2015 P&A expenditures of approximately $300 million • 4-year P&A plan (2016-2019) reviewed by BSEE • 2013 Safety in Seas award for decommissioning (Coast Guard, BSEE) • Majority of P&A obligation is tied to long lived (10+ years) properties, specifically Pompano and Amberjack

16 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Pompano Hub Production at 12 Year High Amethyst MC72 MC26 Derbio MC27 MC28 MC29 MC71 VK989 VK99 0 Cardona MC117MC113 Pompano Field Rampart • Acquired in 2011 from BP for $168 million • Cardona program increased production above 20,000 net boepd • Pompano platform economic in current price environment • Program expected to add 5,000 net boepd by third quarter of 2017 • Unit LOE reduced from $15.68 in 2012 to estimated $4.85 in 2016 • Platform capacity of 60 Mbopd, 200 MMcfpd Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone. 0 10 20 30 40 50 60 70 N e t MB O EP D Pompano Complex Pompano Platform Cardona 4-7 Amethyst Pompano Platform Program Derbio Rampart Deep Rampart Shallow Actual Forecast Derbio, Rampart Shallow, and Rampart Deep Mean Success -1,000 -500 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 2 0 1 1 2 0 1 2 2 0 1 3 2 0 1 4 2 0 1 5 2 0 1 6 2 0 1 7 2 0 1 8 2 0 1 9 2 0 2 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 Cu m u la tive Ca sh F lo w s $ M M Pompano Cash Flows Pompano Current With Exploration Consensus Pricing, Derbio, Rampart Shallow, and Rampart Deep Mean Success Cardona/Amethyst Program

17 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Cardona Subsea Development Flows to Pompano Hub • SGY 65% WI, 57% NRI • 4 well tie-back loop • Enables future tie backs • 4 wells producing 19,000 boepd (gross) • Gross EUR: 12-43 mmboe • Production handing fees exceed incremental LOE Cardona Project (as of May 2016) Shale Out Shale Out #TB-9 Salt Shale Out Cardona South Cardona #6 Cardona Cardona #7 Cardona #4 Cardona #5 Cardona No. 6: P8 Producing • Online late August 2015 • M83A behind pipe Cardona No. 7: M83A Producing • Online February 2016 Cardona No. 4 and 5: M83A Producing • On production November 2014 • Produced 2.5 mmboe as of April 2016 • M83-7 behind pipe (Cardona #5) Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone.

18 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Pompano Platform Development Program Supports Production Profile in 2017-2018 M b o e/ d A-15 ST •Mt Silverthrone A-11 •Mt. Hunter A-34 •Mt. Providence A-25 ST •Mt. Bona Pompano Platform Rig • 100% SGY • 4 drill wells (one complete, 3 left to drill) • 1 workover (complete) • Remaining net investment (4/1): $143 mm • EUR: 7 – 23 gross mmboe • Estimated development cost: $15 per boe • Estimated incremental LOE $0.67 boe Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone. Risked Production Profile Pompano Platform H&P 100 Rig on Pompano

19 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Existing Leasehold Exposes Stone to Significant Potential Lafayette Houston New Orleans Pompano Amberjack Lamprey Derbio Audubon Ship Shoal 113 Phinisi Enterprise Apple Parmer • 110 Deep water leases • 11 High potential prospects • 15 Tie-back exploration projects • 10 Platform development wells Legend Business Plan Prospect Rialto KuskulanaGuadalupe MP 288 Horned Lark Moore Mica Deep Cardona Pyrope Ruby Luling Banyan Gundalow Prospect Apple Derbio Lamprey Rampart Deep Rampart Shallow Luling Horned Lark (Shelf) Banyan Audubon Rialto Kuskulana WI 100% 100% 100% 100% 100% 100% 100% 100% 100% 50% 33% EUR 40-334 23-182 228-897 26-90 13-73 23-72 1-7 9-30 10-102 17-175 12-67 mmboe * P90-P10 range Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone. Rampart Deep Rampart Shallow

20 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Near-Term Exploration Prospects Tie-back to Existing Infrastructure • SGY 100% • EUR 23 - 182 mmboe • 4 mile tie-back to Pompano • Estimated DHC $59 mm Derbio Prospect • SGY 100% • EUR 13 - 73 mmboe • 9 mile tie-back to Pompano • Estimated DHC $58 mm Rampart Shallow Prospect Pompano Amberjack Rampart Pompano Amberjack Derbio Audubon Audubon • Tie-backs to existing infrastructure add minimal incremental LOE • Derbio and Rampart provide exploration tests in 2017 & 2018 that could be brought online with short cycle times • Derbio and Rampart are low risk amplitude driven prospects • Company plans to seek farm-down opportunities Derbio Rampart Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone. • SGY 100% • EUR 26 - 90 mmboe • 9 mile tie-back to Pompano • Estimated DHC $61 mm Rampart Deep Prospect Pompano Amberjack Rampart Salt Audubon Derbio Salt

21 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT 2 1 Great White • SGY 100% • Estimated 104 - 547 mmboe gross • Great White producing to north • Estimated DHC $51 mm (initial well) Lamprey 3 Lamprey AC 857 #1  Great White cumulative production est. 100 mmboe  Frio and Wilcox appear to thicken at Lamprey N S Lamprey Prospect Provides Exploration Catalyst Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone.

22 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT 0 10 20 30 40 50 60 YE 2011 YE 2015 PUD Reserves PDNP Reserves PDP Reserves Cum Production Net mmboe 0 5 10 15 20 YE 2009 YE 2015 PUD Reserves PDNP Reserves PDP Reserves Cum Production Net mmboe Pompano Amberjack Deep Water Acquisitions Leveraged by Operational / Subsurface Capabilities Infrastructure-Lead Exploitation • Leverage hubs to develop subsea assets Proven Track Record in the Deep Water • Pompano and Amberjack Success Focus for Future Acquisitions • Deep water Gulf of Mexico from Majors • Prefer to operate All YE 2015 estimated proved, probable and possible reserves were fully engineered by Netherland, Sewell, and Associates, Inc. as of 12/31/15. All YE 2011 estimated proved, probable and possible reserves were fully engineered by Netherland, Sewell, and Associates, Inc. as of 12/31/11. All YE 2009 estimated proved, probable and possible reserves were fully engineered by Netherland, Sewell, and Associates, Inc. as of 12/31/09. See “Reserves” under Disclaimer section.

23 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Appalachia Acreage Position Marcellus Leasehold PROSPECT GROSS ACRES NET ACRES NET HBP ACRES MARY 54,419 40,217 25,045 HEATHER 5,801 5,801 5,801 BUDDY 7,933 6,890 3,445 TANNER 4,230 4,078 4,078 WV Subtotal 72,383 56,986 38,369 CHRISTINE 21,283 20,929 0.00 JOSIE 928 928 0.00 ANDIE 9,887 9,834 0.00 PA Subtotal 32,098 31,691 0.00 TOTAL 104,481 88,677 38,369 UTICA Leasehold PROSPECT GROSS ACRES NET ACRES NET HBP ACRES MARY 54,419 34,217 17,545 HEATHER 5,801 5,801 5,801 BUDDY 7,933 6,890 3,445 WV Subtotal 68,153 46,908 26,791 CHRISTINE 21,283 20,929 0.00 PA Subtotal 21,283 20,929 0.00 TOTAL 89,436 67,837 26,791 40,217 5,801 6,890 4,078 20,929 928 9,834 Marcellus Net Acreage by Field MARY HEATHER BUDDY TANNER CHRISTINE JOSIE ANDIE 34,217 5,801 6,890 20,929 Utica Net Acreage by Field MARY HEATHER BUDDY CHRISTINE

24 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Quality Assets and Performance s Mary Field • Stacked wet-gas Marcellus and dry-gas Utica • 81 producing Marcellus wells and 1 producing Utica well prior to 2015 suspension • 59 partially drilled wells, 25 of which are awaiting completion • 393 remaining gross other identified Marcellus drilling locations • 353 remaining gross other identified Utica drilling locations Heather Field • Stacked wet-gas Marcellus with dry-gas Utica potential • 26 producing Marcellus wells • 17 remaining gross other identified Utica drilling locations Buddy Field • 2 producing dry-gas Marcellus wells Christine Area • Undeveloped 0 50 100 150 2011 2012 2013 2014 2015 m m cf ep d Appalachia Production* * Mary Field shut-in September 2015, shaded area reflects estimated incremental production rate assuming the field were not shut-in Shut-In 0 250 500 750 2011 2012 2013 2014 b cf e Appalachia Proved Reserves** 2015 Drilling and Completion Suspended 2014 Year-end Proved reserves 526 bcfe** Probable and Possible reserves 531 bcfe** Mary Heather Buddy **All estimated proved, probable and possible reserves were fully engineered by Netherland, Sewell, and Associates, Inc. as of 12/31/14. See “Reserves” under Disclaimer section. Substantially all of Stone’s estimated proved reserves in Appalachia were reclassified to contingent resources in 2015.

25 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Stone Energy Utica Test Well Pribble 6HU: Lateral length: 3,555’ EUR: 8.62 bcf EUR/1,000: 2.54 bcf/1,000’ Utica Dry Gas Type Curve  Assumes 6,500’ lateral length  Type Curve EUR: 16.4 Bcf  Flat Portion: 20mmscf (4 months)  Di: 67%  B: 1.2  Def: 5%  EUR: 2.52 Bcf/ 1,000’ Pribble EUR: 2.54 Bcf/ 1,000’ Industry estimates: 2.4 – 2.8 Bcf/ 1,000’ EQT Green County estimate: 4.3 – 5.9 Bcf/ 1,000’  Production data normalized to 6,500’ lateral  Type curve based on public, proprietary third- party and Stone Energy data Dry Gas Utica Performance & Type Well Lessons Learned  Optimize lateral azimuth  Proppant selection  Pressure management Estimates of ultimate recovery (EUR), resource ranges, and initial rates of production and drilling schedules are internally estimated by Stone.

26 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Sources: Range Resources, Analyst Estimates, Bloomberg, Inside-FERC Appalachia Basin - Forward Market as of May 3rd, 2016 • Gross netbacks projected to improve from $1.41 to $2.40 by 2019 • HH - App M2 projected to drop from $0.95 in 2016 to $0.63 in 2019 • Henry Hub projected to rise from $2.36 for rest of 2016 to $3.03 in 2019 Improving Infrastructure / Forward Price Curves Highlight Optionality 2015 2016 2017 2018

27 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Agenda  Executive Summary  Asset Overview and Operations Update Gulf of Mexico Appalachia  Business Plan Overview and Long-Term Forecast  Appendix

28 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Long-Term Forecast – Assumptions Overview Production • Production profiles based on Stone’s best technical estimate for producing properties • Near-term developments and prospects utilize Stone internally technically-reviewed and risk- weighted estimates of future production • Some later dated exploration prospects based on Stone’s internal P50 analysis • Downtime applied throughout the calendar year; however, increased during hurricane season Development Capital • Development capital and schedule based on Stone estimates of activity, and assumes availability and acceptable cost of adequate capital • All recompletes, sidetracks and new drill wells must achieve minimum economic thresholds in order to be funded • Cost estimates are based on Stone recent experience and do not incorporate additional costs savings • Asset retirement obligations incorporated as fields are shut-in per company schedule Exploration Capital • Exploration drilling campaign high-graded based on anticipated IRR of risked asset profiles • Anticipates between two and three exploration wells drilled each year 2017-2020 • Additional exploration prospects available to be opportunistically developed but currently unscheduled • Exploration capital assumes availability and acceptable cost of adequate capital • Stone maintains between 40-100% WI in its prospect inventory at May 2016 • Anticipated that prospects would be drilled between a 33.33 – 50.00% WI Commodity Prices • Analyzed updated baseline case at strip price deck as of 5/27/2016 (business plan case is analyzed at consensus price deck as of 5/3/16) • Differentials and realizations vary by producing field • Residual hedges (25% of production) to roll-off in 2016 Operating Expenses • LOE, production taxes and transportation were forecasted based on each fields profile • Assumes favorable resolution of uneconomic agreements • SG&A forecasted to be $88 million for updated baseline case ($91mm for business plan case) in 2016 (including capitalized G&A), a reduction of 12% (7% for business plan case) compared to 2015, with 26% decrease in 2017 (1.5% increase for business plan case) and 1.02% increase (1.5% increase for business plan case) per annum thereafterNote: See Disclaimer page of Presentation

29 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Updated Baseline Case Overview – Price Decks $2.17 $2.24 $2.99 $3.03 $3.05 $3.13 $3.48 $4.00 $4.00 $4.00 $2.23 1.00 2.00 3.00 $4.00 Strip Upside Price Sensitivity Consensus ($/Mmbtu) Henry Hub Pricing $49.33 $44.97 $51.76 $52.74 $54.07 $55.38 $65.65 $80.00 $80.00 $80.00 $41.80 $53.01 $62.44 $63.59 $65.50 30.00 55.00 $80.00 Strip Upside Price Sensitivity Consensus ($/bbl) WTI Pricing Note: Market data as of 5/27/16 (1) Consensus pricing (1)

30 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Updated Baseline Case – Strip (Strip Price Deck as of 5/27/2026) LONG-TERM FORECAST – SUMMARY ($mm, unless stated otherwise) Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 Oil (Mbbl/d) 18 17 14 17 17 16 15 13 13 13 18 21 NGL (Mbbl/d) 4 2 2 8 4 9 8 8 9 9 10 11 Gas (Mmcf/d) 77 43 36 108 66 124 111 100 119 115 127 138 Oil ($/bbl) $31.22 $44.93 $50.06 $47.12 $42.83 $47.16 $49.46 $50.08 $50.38 $52.56 $54.04 $55.19 NGL ($/bbl) 12.99 12.74 14.74 11.70 12.51 13.91 16.35 18.94 19.37 19.80 20.21 20.48 Gas ($/mcf) 1.70 1.48 1.73 2.02 1.80 2.41 2.62 2.69 2.77 2.91 3.08 3.27 Total Production (Mbbl/d) 35 26 22 43 32 46 42 38 42 42 48 55 Oil and Gas Revenue $67 $78 $74 $102 $322 $437 $425 $396 $424 $444 $561 $671 Hedging Revenue 13 9 7 6 35 -- -- -- -- -- -- -- Other Operational Revenue 0 1 1 1 3 5 5 5 5 5 5 5 Revenue $81 $88 $82 $108 $359 $442 $430 $400 $429 $449 $565 $676 (-) LOE and TP&G (20) (26) (29) (36) (111) (146) (135) (125) (129) (121) (143) (156) (-) Production Taxes (0) (0) (0) (1) (2) (8) (8) (8) (10) (9) (10) (12) (-) SG&A (18) (17) (17) (14) (65) (47) (48) (49) (50) (50) (51) (52) EBITDA $42 $45 $36 $57 $180 $241 $239 $219 $241 $269 $361 $455 (-) Capex (84) (36) (13) (19) (151) (219) (158) (222) (219) (246) (259) (154) (-) Capitalized G&A (6) (6) (6) (5) (23) (18) (18) (18) (18) (19) (19) (19) (-) Payment of AROs (5) (7) (5) (1) (18) (65) (47) (59) (21) (3) -- -- (-) Rig Farm-Out, Cold Stack, Termination Expenses, Other (6) (5) (2) (5) (19) -- -- -- -- -- -- -- (+) Stock Based Compensation Expense 2 3 3 3 12 7 7 7 7 7 7 7 (+) Estimated Tax Refunds -- -- 27 -- 27 25 23 -- -- -- -- -- (-) Interest on Surety Bonding -- (2) (0) (0) (2) (3) (5) (6) (6) (4) (4) (4) (-) Change in Net Working Capital (40) -- -- -- (40) -- -- -- -- -- -- -- Unlevered Free Cash Flow ($97) ($7) $39 $31 ($34) ($33) $41 ($79) ($16) $4 $87 $286 Note: Stone internal estimates. Excludes transaction, restructuring, and interest expenses. See Disclaimer page of Presentation. See also Long-Term Forecast – Assumptions Overview. For reconciliation of non-GAAP measures of EBITDA, and unlevered free cash flow to the GAAP measures of net income and cash flow from operations see “Non-GAAP Reconciliation of Updated Baseline Case - Strip” in the appendix. * * *

31 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Business Plan Case – Consensus (Consensus Price Deck as of 5/3/2016) LONG-TERM FORECAST – SUMMARY ($mm, unless stated otherwise) Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 Oil (Mbbl/d) 18 17 14 17 17 16 15 13 13 13 17 20 NGL (Mbbl/d) 4 2 2 8 4 9 8 8 9 8 8 8 Gas (Mmcf/d) 77 43 36 108 66 125 111 98 119 110 108 107 Oil ($/bbl) $31.22 $39.06 $43.01 $42.49 $38.63 $46.88 $52.68 $55.59 $56.79 $59.53 $61.21 $64.48 NGL ($/bbl) 12.99 11.28 12.62 10.55 11.51 14.02 18.04 22.11 22.81 21.57 22.93 23.80 Gas ($/mcf) 1.70 1.51 1.73 1.92 1.76 2.29 2.62 2.88 3.05 2.88 2.89 2.91 Total Production (Mbbl/d) 35 26 22 43 32 46 42 37 42 40 43 46 Oil and Gas Revenue $67 $69 $65 $93 $294 $431 $448 $428 $476 $468 $555 $655 Hedging Revenue 13 11 9 7 41 -- -- -- -- -- -- -- Other Operational Revenue 0 1 1 1 3 5 5 5 5 5 5 5 Revenue $81 $81 $75 $101 $337 $436 $453 $433 $481 $473 $560 $659 (-) LOE and TP&G (20) (26) (31) (38) (115) (154) (144) (128) (130) (124) (138) (143) (-) Production Taxes (0) (0) (0) (1) (2) (8) (8) (8) (11) (8) (8) (7) (-) SG&A (18) (17) (17) (17) (69) (68) (69) (70) (71) (73) (74) (75) EBITDA $42 $38 $26 $45 $151 $206 $231 $227 $269 $268 $341 $435 (-) Capex (84) (36) (13) (19) (151) (223) (158) (229) (208) (201) (194) (66) (-) Capitalized G&A (6) (6) (6) (6) (24) (25) (25) (26) (26) (26) (27) (27) (-) Payment f AROs (5) (7) (5) (1) (18) (65) (47) (59) (21) (3) -- -- (-) Rig Farm-Out, Cold Stack, Termination Expenses, Other (6) (5) 3 3 (6) -- -- -- -- -- -- -- (+) Stock Based Compensation Expense 2 3 3 3 12 13 13 13 13 13 13 13 (+) Estimated Tax Refunds -- -- 27 -- 27 25 23 -- -- -- -- -- (-) Interest on Surety Bonding -- (2) (0) (0) (2) (4) (5) (7) (6) (4) (4) (4) (-) Change in Net Working Capital (40) -- -- -- (40) -- -- -- -- -- -- -- Unlevered Free Cash Flow ($97) ($14) $35 $25 ($51) ($72) $32 ($81) $21 $46 $129 $351 Note: Stone internal estimates. Excludes transaction, restructuring, and interest expenses. See Disclaimer page of Presentation. See also Long-Term Forecast – Assumptions Overview. For reconciliation of non-GAAP measures of EBITDA, and unlevered free cash flow to the GAAP measures of net income and cash flow from operations see “Non-GAAP Reconciliation of Business Plan Case - Consensus” in the appendix.

32 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Agenda  Executive Summary  Asset Overview and Operations Update Gulf of Mexico Appalachia  Business Plan Overview and Long-Term Forecast  Appendix

33 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Projected Capital Expenditures by Operating Area Projected Capex ($ mm) All Divisions 2016 2017 2018 2019 2020 2021 2022 2023 APPALACHIA (13) (68) (2) (111) (24) (68) (88) (111) GOM (includes ARO) (156) (216) (203) (170) (216) (181) (171) (43) TOTAL (169) (284) (205) (281) (240) (249) (259) (154) Note: Stone internal estimates. Excludes transaction, restructuring, and interest expenses. See Disclaimer page of presentation. See also Long-Term Forecast – Assumptions Overview.

34 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT PV10 Projection Gulf of Mexico Developed Producing Developed NonProducing Undeveloped 1/1/16 PV10 (2) 1/1/17 PV10 (3) 1/1/18 PV10 (3) $499 MM $57 MM $157 MM $440 MM $95 MM $169 MM $532 MM $38 MM $67 MM Developed Producing Developed NonProducing Undeveloped Appalachia 1/1/16 PV10 (2) 1/1/17 PV10 (3) 1/1/18 PV10 (3) $0 MM $0 MM $0 MM $139 MM $121 MM $0 MM $234 MM $106 MM $0 MM 2016 Assumptions: • FY16 Prod: 8.5 mmboe • Cardona 7 PUD to PDP • Pompano Silverthrone PUD to PDP 2017 Assumptions: • FY17 Prod: 7.7 mmboe • Pompano Bona PUD to PDP • Pompano Providence PUD to PDP 2016 Assumptions: • FY16 Prod: 3.0 mmboe • New TP&G contract • PDP rebooked • DUC’s rebooked 2017 Assumptions: • FY17 Prod: 9.2 mmboe • DUC’s from PDNP to PDP Exploration (4) $334 MM Note: See Disclaimer page of Presentation. (2) PV10 for 1/1/16 does not reflect the standardized measure used for SEC reporting purposes. The differences between 1/1/16 PV10 and the standardized measure as of 12/31/15 is attributable to $149 million associated with the exclusion of plugging and abandonment costs from the 1/1/16 cash flows, offset by the negative effects of commodity prices of -$40 million. All cash flows were discounted at 10%. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the table above, represent the fair value of our estimated oil, natural gas and NGL reserves (4) Exploration PV10 is not reflective of proved reserves or standardized measure. Exploration PV10 reflects a net risk weighted economic analysis which includes internal estimates of ultimate recovery with associated exploration, development and production costs for Stone’s Apple and Rampart Deep prospects. You should not assume that the discounted future net cash flows, referred to in the table above, represent the fair value of our estimated oil, natural gas and NGL reserves. 2017 Assumptions: • Apple and Rampart Deep – drilled not booked SEC 12/31/15 PV10 (1) $392 MM $43 MM $169 MM $0 MM $0 MM $0 MM (1) PV10 for 12/31/15 reflects the standardized measure of discounted future net cash flows (based on 10% annual discount rate) related to the estimated proved oil, natural gas and NGL reserves as presented in the 2015 Annual Report on Form 10-K. The undiscounted future cash flows were $591 million. You should not assume that the discounted future net cash flows, referred to in the table above, represent the fair value of our estimated oil, natural gas and NGL reserves. SEC 12/31/15 PV10 (1) (3) PV10 for 1/1/17 and 1/1/18 do not reflect the standardized measure for reserve valuation. The lack of an actual prior 12 month average commodity price for these time periods makes a reconciliation to standardized measure administratively impracticable. PV10 for 1/1/17 and 1/1/18 reflect internally generated estimates of ultimate recovery at strip pricing. These numbers include future estimates of shifts in reserve category and exclude plugging and abandonment costs. All cash flows were discounted at 10%. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the table above, represent the fair value of our estimated oil, natural gas and NGL reserves. You should not assume that the discounted future net cash flows, referred to in the table above, represent the fair value of our estimated oil, natural gas and NGL reserves

35 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Capital Light Case – Strip (Strip Price Deck as of 5/27/2016) LONG-TERM FORECAST – SUMMARY ($mm, unless stated otherwise) Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 Oil (Mbbl/d) 18 17 14 17 17 15 14 12 10 8 7 7 NGL (Mbbl/d) 4 2 2 8 4 7 5 4 4 3 3 2 Gas (Mmcf/d) 77 43 36 108 66 96 82 65 53 49 40 33 Oil ($/bbl) $31.22 $44.93 $50.06 $47.12 $42.83 $48.92 $50.56 $51.94 $53.18 $54.32 $55.57 $56.37 NGL ($/bbl) 12.99 12.74 14.74 11.70 12.51 14.28 16.63 18.92 19.38 19.80 20.20 20.48 Gas ($/mcf) 1.70 1.48 1.73 2.02 1.80 2.43 2.62 2.69 2.76 2.86 2.99 3.18 Total Production (Mbbl/d) 35 26 22 43 32 38 33 27 22 20 17 15 Oil and Gas Revenue $67 $78 $74 $102 $322 $391 $375 $316 $265 $235 $215 $195 Hedging Revenue 13 9 7 6 35 -- -- -- -- -- -- -- Other Operational Revenue 0 1 1 1 3 5 5 5 5 5 5 5 Revenue $81 $88 $82 $108 $359 $396 $380 $321 $270 $240 $219 $200 (-) LOE and TP&G (20) (26) (29) (36) (111) (126) (115) (101) (88) (80) (75) (72) (-) Production Taxes (0) (0) (0) (1) (2) (5) (5) (4) (3) (3) (3) (2) (-) SG&A (18) (17) (17) (12) (64) (36) (36) (37) (37) (38) (38) (39) EBITDA $42 $45 $36 $59 $181 $229 $224 $180 $142 $119 $103 $86 (-) Capex (84) (36) (13) (19) (151) (141) (44) (24) (11) (3) (22) (3) (-) Capitalized G&A (6) (6) (6) (4) (22) (18) (18) (18) (18) (19) (19) (19) (-) Payment of AROs (5) (7) (5) (1) (18) (65) (47) (59) (21) (3) -- -- (-) Rig Farm-Out, Cold Stack, Termination Expenses, Other (6) (5) (2) (8) (22) -- -- -- -- -- -- -- (+) Stock Based Compensation Expense 2 3 3 3 12 5 5 5 5 5 5 6 (+) Estimated Tax Refunds -- -- 27 -- 27 25 23 -- -- -- -- -- (-) Interest on Surety Bonding -- (2) (0) (0) (2) (3) (3) (4) (4) (3) (3) (4) (-) Change in Net Working Capital (40) -- -- -- (40) -- -- -- -- -- -- -- Unlevered Free Cash Flow ($97) ($7) $39 $30 ($35) $33 $140 $80 $93 $96 $64 $66 * Note: Stone internal estimates. Excludes transaction, restructuring, and interest expenses. See Disclaimer page of Presentation. See also Long-Term Forecast – Assumptions Overview, and in addition assumes no Gulf of Mexico exploration drilling, no completion of drilled but uncompleted Appalachia wells, and no new well or partial Appalachia drilling, and associated reductions in costs and expenses including additional reductions in SG&A commencing, in 2017. For reconciliation of non-GAAP measures of EBITDA, and unlevered free cash flow to the GAAP measures of net income and cash flow from operations see “Non-GAAP Reconciliation of Capital Light Plan - Consensus” in the appendix. * *

36 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Reconciliation of EBITDA to Net Income Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 EBITDA $ 42 $ 45 $ 36 $ 57 $ 180 $ 241 $ 239 $ 219 $ 241 $ 269 $ 361 $ 455 -DD&A $ (62) $ (40) $ (35) $ (66) $ (202) $ (141) $ (90) $ (92) $ (106) $ (120) $ (153) $ (187) -Accretion $ (10) $ (10) $ (10) $ (10) $ (40) $ (15) $ (12) $ (10) $ (9) $ (9) $ (11) $ (12) -Provision for Writedown $ (129) $ - $ - $ - $ (129) $ - $ - $ - $ - $ - $ - $ - -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (18) $ (19) $ (20) $ (20) $ (20) -Other Operational Expense $ (12) $ (7) $ 2 $ (2) $ (19) $ (3) $ (5) $ (6) $ (6) $ (4) $ (4) $ (4) -Restructuring Fees $ (1) $ (15) $ (20) $ (17) $ (53) $ - $ - $ - $ - $ - $ - $ - Net Income (Loss) - Before Tax $ (187) $ (30) $ (30) $ (41) $ (288) $ 64 $ 114 $ 93 $ 101 $ 116 $ 173 $ 232 -Estimated Income Tax $ (2) $ (2) $ (2) $ (1) $ (7) $ - $ - $ - $ - $ - $ - $ - Net Income (Loss) - After Tax $ (189) $ (32) $ (32) $ (42) $ (295) $ 64 $ 114 $ 93 $ 101 $ 116 $ 173 $ 232 Reconciliation of Unlevered Free Cash Flow to Cash Flow From Operations Unlevered Free Cash Flow $ (97) $ (7) $ 39 $ 31 $ (34) $ (33) $ 41 $ (79) $ (16) $ 4 $ 87 $ 286 +Capex $ 84 $ 36 $ 13 $ 19 $ 151 $ 219 $ 158 $ 222 $ 219 $ 246 $ 259 $ 154 +Capitalized SG&A $ 6 $ 6 $ 6 $ 5 $ 23 $ 18 $ 18 $ 18 $ 18 $ 19 $ 19 $ 19 -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (18) $ (19) $ (20) $ (20) $ (20) -Other $ 51 $ (15) $ (20) $ (18) $ (2) Cash Flow from Operations $ 29 $ 17 $ 35 $ 34 $ 113 $ 186 $ 199 $ 143 $ 202 $ 249 $ 345 $ 439 Non-GAAP Reconciliation of Updated Baseline Case - Strip

37 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Reconciliation of EBITDA to Net Income Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 EBITDA $ 42 $ 38 $ 26 $ 45 $ 151 $ 206 $ 231 $ 227 $ 269 $ 268 $ 341 $ 435 -DD&A $ (62) $ (40) $ (35) $ (66) $ (203) $ (145) $ (107) $ (106) $ (127) $ (130) $ (154) $ (194) -Accretion $ (10) $ (10) $ (10) $ (10) $ (40) $ (15) $ (12) $ (10) $ (9) $ (9) $ (11) $ (12) -Provision for Writedown $ (129) $ - $ - $ - $ (129) $ - $ - $ - $ - $ - $ - $ - -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (18) $ (19) $ (20) $ (20) $ (20) -Other Operational Expense $ (12) $ (7) $ 2 $ (2) $ (19) $ (3) $ (5) $ (6) $ (6) $ (4) $ (4) $ (4) -Restructuring Fees $ (1) $ (15) $ (20) $ (17) $ (53) $ - $ - $ - $ - $ - $ - $ - Net Income (Loss) - Before Tax $ (187) $ (37) $ (40) $ (54) $ (318) $ 25 $ 89 $ 87 $ 108 $ 105 $ 152 $ 205 -Estimated Income Tax $ (2) $ (2) $ (2) $ (1) $ (7) $ - $ - $ - $ - $ - $ - Net Income (Loss) - After Tax $ (189) $ (39) $ (42) $ (55) $ (325) $ 25 $ 89 $ 87 $ 108 $ 105 $ 152 $ 205 Reconciliation of Unlevered Free Cash Flow to Cash Flow From Operations Unlevered Free Cash Flow $ (97) $ (14) $ 35 $ 25 $ (51) $ (72) $ 32 $ (81) $ 21 $ 46 $ 129 $ 351 +Capex $ 84 $ 36 $ 13 $ 19 $ 151 $ 223 $ 158 $ 229 $ 208 $ 201 $ 194 $ 66 +Capitalized SG&A $ 6 $ 6 $ 6 $ 6 $ 24 $ 25 $ 25 $ 26 $ 26 $ 26 $ 27 $ 27 -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (18) $ (19) $ (20) $ (20) $ (20) -Other $ 51 $ (15) $ (20) $ (18) $ (2) Cash Flow from Operations $ 29 $ 10 $ 31 $ 29 $ 97 $ 158 $ 197 $ 156 $ 236 $ 253 $ 330 $ 424 Non-GAAP Reconciliation of Business Plan Case - Consensus

38 PRELIMINARY DRAFT SUBJECT TO REVISION | SUBJECT TO FRE408 AND CONFIDENTIALITY AGREEMENT Reconciliation of EBITDA to Net Income Q1'16 Q2'16 Q3'16 Q4'16 FY'16 FY'17 FY'18 FY'19 FY'20 FY'21 FY'22 FY'23 EBITDA $ 42 $ 45 $ 36 $ 59 $ 181 $ 229 $ 224 $ 180 $ 142 $ 119 $ 103 $ 86 -DD&A $ (62) $ (40) $ (35) $ (66) $ (202) $ (140) $ (77) $ (63) $ (54) $ (48) $ (42) $ (38) -Accretion $ (10) $ (10) $ (10) $ (10) $ (40) $ (15) $ (12) $ (9) $ (7) $ (7) $ (7) $ (8) -Provision for Writedown $ (129) $ - $ - $ - $ (129) $ - $ - $ - $ - $ - $ - $ - -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (18) $ (19) $ (20) $ (20) $ (20) -Other Operational Expense $ (12) $ (7) $ (3) $ (9) $ (30) $ (2) $ (3) $ (6) $ (4) $ (4) $ (5) $ (5) -Restructuring Fees $ (1) $ (15) $ (20) $ (17) $ (53) $ - $ - $ - $ - $ - $ - $ - Net Income (Loss) - Before Tax $ (187) $ (30) $ (35) $ (46) $ (298) $ 54 $ 114 $ 84 $ 58 $ 40 $ 29 $ 15 -Estimated Income Tax $ (2) $ (2) $ (2) $ (1) $ (7) $ - $ - $ - $ - $ - $ - Net Income (Loss) - After Tax $ (189) $ (32) $ (37) $ (47) $ (305) $ 54 $ 114 $ 84 $ 58 $ 40 $ 29 $ 15 Reconciliation of Unlevered Free Cash Flow to Cash Flow From Operations Unlevered Free Cash Flow $ (97) $ (7) $ 39 $ 30 $ (35) $ 33 $ 140 $ 80 $ 93 $ 96 $ 64 $ 66 +Capex $ 84 $ 36 $ 13 $ 19 $ 151 $ 141 $ 44 $ 24 $ 11 $ 3 $ 22 $ 3 +Capitalized SG&A $ 6 $ 6 $ 6 $ 4 $ 22 $ 18 $ 18 $ 18 $ 18 $ 19 $ 19 $ 19 -Interest Expense $ (15) $ (3) $ (3) $ (3) $ (25) $ (18) $ (18) $ (19) $ (19) $ (20) $ (22) $ (22) -Other $ 51 $ (15) $ (20) $ (18) $ (2) Cash Flow from Operations $ 29 $ 17 $ 35 $ 32 $ 111 $ 174 $ 184 $ 103 $ 103 $ 98 $ 83 $ 66 Non-GAAP Reconciliation of Capital Light Case - Strip