Energy XXI Gulf Coast (EGC) 8-K Energy Xxi Gulf Coast Announces Third Quarter 2017

Exhibit 99.2

www.energyxxi.com Third Quarter 2017 Earnings Conference Call November 14, 2017

Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These statements, including those relating to the intent, beliefs, plans, or expectations of EGC are based upon current expectations and are subject to a number of risks, uncertainties, and assumptions. It is not possible to predict or identify all such factors and the following list should not be considered a complete statement of all potential risks and uncertainties relating to emergence from Chapter 11, the recent change in EGC’s senior management team, or EGC’s oil and gas reserves, including, but not limited to: (i) the effects of the departure of our senior leaders and the hiring of a new CEO and CFO on our employees, suppliers, regulators and business counterparties; (ii) our ability to maintain sufficient liquidity and/or obtain adequate additional financing necessary to fund our operations, capital expenditures and to execute our business plan, develop our proved undeveloped reserves within five years and to meet our other obligations; (iii) our ability to comply with covenants under our three-year secured credit facility; (iv) further or sustained declines in the prices we receive for our oil and natural gas production; and (v) other risks and uncertainties. These risks and uncertainties could cause actual results, including project plans and related expenditures and resource recoveries, to differ materially from those described in the forward-looking statements. For a more detailed discussion of risk factors, please see Part I, Item 1A, “Risk Factors” of the Transition Report on Form 10-K for the transition period ended December 31, 2016 filed by EGC for more information. EGC assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law. 2

Non-GAAP Measures and Cautionary Language on Hydrocarbon Reserves EGC refers “PV-10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and development costs but does not include effects, if any, of income taxes, which is included in standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure . PV-10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”). Management believes that the non-U.S. GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. EGC believes the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP. This presentation includes NSAI-prepared estimates for proved and probable reserves and aggregated proved and probable reserves as of March 31, 2017, with each category of reserves estimated in accordance with SEC guidelines and definitions. The SEC permits the optional disclosure of probable reserves. The SEC defines "probable" reserves as "those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." EGC has included the NSAI estimate of proved, probable and aggregated proved and probable reserves in this release because management believes it is useful information that is widely used by the investment community in the valuation, comparison and analysis of companies. However, the Company notes that the SEC prohibits companies from aggregating proved and probable reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Actual quantities that may be ultimately recovered from EGC's interests may differ substantially from the NSAI estimates included in this press release. Factors affecting ultimate recovery include the scope of EGC's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, regulatory approvals, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints and other factors; actual drilling results, including geological and mechanical factors affecting recovery rates; and budgets based upon our future evaluation of risk, returns and the availability of capital. With respect to commodity prices, there can be no assurance that actual oil and gas prices will be consistent with the forward strip pricing case or any of the other pricing assumptions described in this press release. 3

EGC Overview 4 Attractive Upside Optionality with Continued Recovery in Oil Prices 109.4 MMBOE Proved Reserves 80% Oil, 2% NGL, 18% Gas 71% Proved Developed 90% Operated 155 Blocks with 57 Producing Fields 616 Gross Producing Wells 422,944 Net Developed Acres 96,503 Net Undeveloped Acres 17,000 Square Miles 3D Seismic Inventory NSAI prepared reserves at March 31, 2017 Pure Play Gulf of Mexico Shelf Company

Steps in the Right Direction 5 Safety and Operational Excellence Experienced Leadership Driving New Culture Commitment to Financial Discipline Recent Strong Results Focus on Maximizing Shareholder Value Strong, proficient executive leadership Douglas E. Brooks - Chief Executive Officer & President Scott Heck - Chief Operating Officer T.J. Thom - Chief Financial Officer Experienced Board of Directors with substantial energy backgrounds Extensive “safety culture” assessment completed & improvement plan underway Develop oil-weighted assets with strong economics at current strip pricing Leadership Engagement: Established HSE and Cost Steering Committees to ensure leadership oversight and support for HSE and cost reduction plans Retained Morgan Stanley to assist with review of strategic alternatives Evaluation, development and implementation of strategic plan Included stand-alone plan and select strategic alternatives Generated Adjusted EBITDA(1) of $102 million YTD2017 2017 development drilling program commenced with successful drilling of West Delta 30 High Tide well that exceeded expectations G&A and LOE sustained reductions demonstrated in 2H 2017 results Continued implementation of LOE and G&A cost saving initiatives 2017 CAPEX expected to be fully funded with available cash and internal cash flow Expanded 2017-18 hedging program by adding more fixed price swap contracts 1 Adjusted EBITDA is a non GAAP measure, see reconciliation to net income in appendix

Third Quarter and Recent Results 6 Produced ~32,600 BOE per day, of which 77% was oil; tropical weather reduced production ~1,200 BOE per day during the third quarter Completed the West Delta 30 High Tide well and initiated production in September; currently producing 650 BOE per day (primarily gas) Reduced total lease operating expense by 9% quarter-over-quarter Lowered general and administrative costs by 27% quarter-over-quarter Benefited from oil price realizations of $49.77 per barrel (before the impact of derivatives) compared to an average WTI price of $48.20 per barrel during the quarter due to positive differentials for crude pricing received for the Company’s production Incurred a net loss of $31.6 million which included a loss on financial derivatives of $12.5 million Generated Adjusted EBITDA of $35.3 million, up 45% from $24.4 million in the prior quarter Reported cash and cash equivalents of $173 million at September 30 Expanded 2018 commodity hedging program Provided summary of strategic alternatives review process

Focused on Operational Excellence HSE steering committee formed to identify actions to improve HSE performance and be a top quartile Company by YE 2018 Completed 3rd party safety cultural assessment Execute improvements in employee engagement and safety initiatives Improve BSEE compliance performance Cost steering committee formed with focus on identifying and delivering value enhancing operational cost savings Near-term opportunity for savings in: boats, helicopters, crews and supply chain management Shore base operation consolidation completed at Grand Isle and Port Fourchon, with initial sustainable savings of $250,000 - $500,000 per month Production optimization Integrity management – increase preventive maintenance projects Reliability management – improve downtime performance Portfolio management – PDP/PDN assessment and execution 7

Production History 8 BOED 2017 Focused on Minimizing Base Oil Decline 70% 3Q 17 vs. 2Q 17 declined due to: Disruptions due to: shut ins from tropical weather, production equipment maintenance, incremental pipeline and facility related unscheduled downtime totaling ~1,200 BOEPD Quarter-to-quarter natural declines High Tide production initiated in September at ~650 BOEPD (primarily gas) Continued focus on low cost workover and recompletion projects Q4 2017 impacted by production curtailments due to Hurricane Nate and pipeline repair and maintenance of ~4,000 – 5,000 BOEPD (1) Midpoint of Q4 2017 guidance, assumed same percentage of oil, gas, and ngl as Q3 2017 Guidance Q1 2017 Q2 2017 Q3 2017 Q4 2017E Gas 10,983 8,150 6,700 5,800 NGL 900 1,000 800 400 Oil 29,100 26,800 25,100 21,800 Total 40,983 35,950 32,600 28,000 40,983 35,950 32,600 28,000 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 75% 77% 77%

Direct LOE, Insurance and Workovers 9 2017 Focused on Sustainable Cost Reduction and Optimization Savings in Multiple Categories Q3 2017 total LOE 9% below Q2 2017 Go forward cost savings initiatives: Sole sourcing items such as labor and chemicals Inventory management, reduction of third party costs and right sizing of operational equipment Consolidated Grand Isle and Port Fourchon shore base facilities Negotiated and realized a lower insurance rate (1) Midpoint of Q4 2017 guidance 9% Guidance 6% Q1 2017 Q2 2017 Q3 2017 Q4 2017E Workover/Maintenance $10.0 $13.4 $8.5 $10.0 Insurance $6.3 $7.1 $5.0 $5.5 Direct Loe $58.9 $64.9 $64.3 $65.0 Total $75.2 $85.4 $77.8 $80.5 $75.2 $85.4 $77.8 $80.5 $- $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 $80.0 $90.0 $MM

Pipeline Facility Fee and Gathering & Transportation 10 2017 Focused on ONRR Refunds and Minimizing Costs Includes Gathering and Transportation credits related to ONRR refunds for the following quarters: Q217 ~$5MM, Q317 ~$11MM Midpoint of Q4 2017 guidance (1) Pipeline Facility Fee flat $10.5 MM quarterly Gathering and Transportation fluctuations due to ONRR refunds in Q2 2017 ~$5 MM and Q3 2017 ~$11 MM ONRR Lookback process continues (2) (1) Guidance (1) (2) (1) Guidance $21.7 $13.2 $18.5 $8.1 Q1 2017 Q2 2017 Q3 2017 Q4 2017E Pipeline Facility Fee $10.5 $10.5 $10.5 $10.5 Gathering&Transportation $11.2 $2.7 $(2.4) $8.0 Total $21.7 $13.2 $8.1 $18.5 $21.7 $13.2 $8.1 $18.5 $(5.0) $- $5.0 $10.0 $15.0 $20.0 $25.0 $MM -$5.0 $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $MM

G&A Expenses(2) 11 Q3 2017 costs 27% below Q2 2017 Total headcount reduced 18% in 2Q 2017 EGC expects $8 to $8.5 MM of annualized G&A and LOE savings from reduced staffing YTD 2017 includes $7.6 MM related to severance costs 2017 also includes restructuring, reorganization and bankruptcy emergence charges Adjusting Staff Levels to Better Align with Operational Plan (1) Midpoint of Q4 2017 guidance Includes non-cash compensation of Q1 $0.9 MM; Q2 $2.9 MM; Q3 $3.0 MM; and Q4E $2.3 MM 27% Guidance $21.6 $20.7 $15.0 $15.0 $- $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 Q1 2017 Q2 2017 Q3 2017 Q4 2017E $MM

Margin Analysis 12 12 $/BOE Cost Controls and Interest Reduction Drives Down Breakeven and Increases Cash Flow in a Rising Commodity Price Environment 1) Q1, Q2 & Q3 2017 excludes non-cash items (1) (1) (1) $19.65 $17.58 $23.57 $26.05 $25.79 $1.33 $3.00 $2.71 $4.09 $2.83 $5.79 $3.10 $5.61 $5.45 $4.00 $15.03 $1.97 $1.03 $1.09 $1.23 $(4.97) $13.54 $9.91 $7.31 $5.12 $(10.00) $- $10.00 $20.00 $30.00 $40.00 $50.00 Q4 2015 Realized Price $36.83/BOE Q4 2016 Realized Price $39.19/BOE Q1 2017 Realized Price $42.83/BOE Q2 2017 Realized Price $43.99/BOE Q3 2017 Realized Price $38.97/BOE LOE/Insurance/Transportation Workover/Maintenance Net G&A Interest Margin

Liquidity Profile 13 September 30, 2017 $MM Total Cash & Cash Equivalents(1) $173 Exit Credit Agreement $290 Less: Amount Drawn ( $74) Less: Letter of Credit Utilization(2) ($203) Total Available Credit Facility(3) $13 Total Liquidity $186 (1) Does not include restricted cash of $32MM which consists of collateral related to bonding and escrow accounts, or $24MM in deposits included in other assets on balance sheet (2) Primarily to secure ExxonMobil plugging and abandonment obligations (3) Subject to restrictions under exit credit agreement For 2018 and beyond, the Company believes that it is reasonably likely that it will be required to make a mandatory prepayment to the Exit Term Loan, with respect to each fiscal quarter following Q1 2018 of approximately 7.5% of the existing term loan balance with the first pay down of ~$5.55 million. This prepayment does not constitute a default under the Exit Facility.

Crude Hedge Profile (As of 11/14/17) Currently Hedged 10,000 bpd of Bal17 $52.30-57.43 LLS Costless Collars 1,500 bpd of Oct17 $51.68 WTI Swaps 3,500 bpd of Nov-Dec17 $51.81 WTI Swaps 8,000 bpd of Cal18 $50.68 WTI Swaps 2,000 bpd of Jan-Jun18 $55.45 LLS Swaps 2,500 bpd of Jan-Jun18 $56.59 Brent Swaps Capacity to Hedge 75% of PDP reduced to 55% of PDP during hurricane season (Jul-Oct) 5 ISDAs in place for 2018 14 Strategy: Opportunistically Support the Base Business At Prices Above Breakeven* * ~$50/bbl including obligatory capital costs excluding discretionary capital spend 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Oct 17 Nov 17 Dec 17 Jan 18 Feb 18 Mar 18 Apr 18 May 18 Jun 18 Jul 18 Aug 18 Sep 18 Oct 18 Nov 18 Dec 18 BOPD LLS Collar WTI Swaps LLS Swaps Brent Swaps Current Hedge Profile Q4 2017 - 2018

2017 Capital Budget Update 2017 Capital Program Funded with Internally Generated Cash Flow and Available Cash 15 Estimated Capital: $115 - $130 million Includes abandonment costs of $50 - $65 million Development Drilling Program Successfully drilled first well: WD30 L-14 ST2 High Tide 100% working interest >50 identified future drilling locations Recompletion Program Performed 8 recompletions in the first nine months of 2017 with good results 1Q17 complex two well program at ST54 yielded strong economic returns and >1,000 BOEPD 3 to 4 recompletions planned for Q4 2017 >100 identified recompletion locations

L Kingstream High Tide Development Update High Tide (L-14 ST2) Targeted three horizons All three targets were found at their expected locations and two of the three sands were thicker than expected 102 feet of net pay versus pre-drill estimate of 60 - 90 feet Well completed in September Early results remain positive D&C Capital(1) ~$9 MM ($1 MM below AFE) Currently managing flowback to maintain reservoir integrity Currently producing ~650 BOEPD (primarily gas) Further analysis occurring to determine gas/fluid interface Minimal incremental LOE (1) net of hurricane costs Locator Map- High Tide and Kingstream High Tide Log – Pay Intervals BF2 Sand B2/B2a Sand C4 Sand High Tide 16

2017 Q4 Guidance (As of 11/14/17) 17 Production is priced 60-70% HLS; 30-40% LLS Reflects impact of curtailments due to Hurricane Nate and pipeline repair and maintenance ~4,000 – 5,000 BOEPD Q4 2017 Capex consists of D&C capex ~$3-$6 MM; P&A capex ~$12-$20 MM; Capitalized G&A ~$4 – $7 MM; Facilities and Other ~$1 – $2 MM 26,000 – 30,000 Boepd(2) Production(1) $60 – $70 MM Direct LOE $8 - $12 MM Workover/Maintenance $5 – $6 MM Insurance $7 - $9 MM Gathering & Transportation $10 - $11 MM Pipeline Facility Fee $13 - $16 MM General & Administrative $25 - $30 MM DD&A $9 – $11 MM Accretion of ARO $20 - $35 MM Capital Expenditures(3) 33,000 – 35,000 Boepd $245 – $255 MM $38 - $42 MM $23 – $24 MM $18 - $20 MM $41 - $43 MM $72 - $75 MM $142 - $147 MM $42 – $44 MM $115 - $130 MM Q4 2017 Full Year 2017

Overview of Strategic Alternative Process 18 Initiated process with Morgan Stanley in late March Merger or consolidation discussion Stand-Alone Plan Capital infusion Forecasts, portfolio evaluation/optimization Reasonable interest in GOM Shelf consolidation (NDAs signed) Existing GOM public E&Ps and private E&Ps PE-backed new entrant Timing and financial market conditions currently not optimal for consolidation in the GOM Potential benefits of consolidation Size and scale Synergies including: Reductions in G&A and operating expenses Increased operating efficiencies Lower break-even costs Significant upside with improving oil prices Focused on Unlocking the Value of Our Resource Base

Overview of Strategic Alternative Process 19 Challenges of consolidation Counterparty balance sheets Offshore recovery lags onshore recovery Challenging public and capital market environment for offshore given current oil price levels No executable combination resulted from the review process All parties continue to believe Shelf consolidation is beneficial and inevitable The Morgan Stanley initiative for consolidation or merger has refocused on Stand-Alone Plan, including seeking new capital EGC remains receptive to future proposals and opportunities The Company is committed to the execution of a sustainable stand-alone strategy

Stand-Alone Path Forward 20 Multiple development plans considered Base Development Plan (subject to capital constraints, see slide #23) Focus on protecting liquidity, covenants and balance sheet Continued G&A and operating cost reductions Minimize production decline with recompletion program and conservative development drilling program Maximize future upside when oil prices recover Remain poised for potential future consolidation Accelerated Development Plan (subject to capital constraints, see slide #24) Range of options reviewed with increased drilling activity Increased drilling in 2018 and especially 2019 Arrests production decline in 2018 and likely achieves production growth in 2019 Remain poised for potential future consolidation Portfolio analysis and rationalization Consider exiting “regional” area deemed “non-strategic” Higher sustained oil prices ($55 - $60) and/or new capital is required to maintain adequate liquidity in 2019 and maintain compliance with credit facility covenants A near-term capital commitment is required to preserve our current reserves and long-range development plans

EGC Scenario Assumptions 21 Strip pricing of approximately $50 WTI for all scenarios Every $1 improvement in oil price increases annual cash flow $7-$9 MM Costs Recent operational focus has identified and is delivering sustainable reductions to lower the inherently high fixed costs of our Shelf assets 2018 Direct LOE estimate of $210 - $240 MM 2018 Workover/Maintenance estimate of $35 - $50 MM 2018 Insurance estimate of $17 - $22 MM 2018 Gathering & Transportation estimate of $30 - $38 MM 2018 Pipeline Facility Fee estimate of: $41 – $43 MM G&A net expense reflects savings from 2017 initiatives and staff reductions 2018 expensed G&A estimate of $50 - $60 MM Additional cost reductions if assets are divested Consistently executing capital recompletions and workovers Highly economic with IRRs of 50% to 150%+ 2018 includes 7 to 12 recompletes and workovers ($5 - $15 MM) (1) Excludes the impact of hedging (1)

EGC Scenario Assumptions 22 Drilling and Completion Capital Projects have minimum return thresholds of 20% IRR and up to 50%+ IRR Preliminary Base Development Plan includes: 5-8 wells in 2018 ($60 - $90 MM) 6-12 wells in 2019 ($60 - $130 MM)* Preliminary Accelerated Development Plan includes: 8-12 wells in 2018 ($80 - $130 MM) 15-20 wells in 2019 ($150 - $200 MM)* Plug and Abandonment (P&A) Capital Includes $50 - $70 MM in 2018 and 2019 Overall liability near-term and long-term could be reduced if assets are divested * Requires additional funds from either increased pricing or new capital to maintain reasonable liquidity in 2019

Production mix 75-85% Oil 2018 exit rate range 28,000 – 32,000 boepd Minimize production decline with recompletion and conservative development drilling program Remain poised for potential future consolidation Drilling and Completion capex 5-8 wells in 2018 and 6-12 wells in 2019 One rig deployed Q2 2018 One rig continues to drill through 2019 Total Capital Spend 2018 D&C $60 - $90 MM Recompletes/Workovers $5 - $15 MM P&A $50 - $70 MM Capitalized G&A, Facilities and Other $26 - $32 MM Requires additional funds from either increased pricing or new capital to maintain reasonable liquidity in 2019 Base Development Scenario Outcomes 23 26,000 – 30,000 28,000 – 33,000 26,000 – 33,000 20,000 22,500 25,000 27,500 30,000 32,500 35,000 2017 Q4E 2018E 2019E BOE/ day Avg. Annual Production 33 – 35 65 – 105 65 – 145 0 20 40 60 80 100 120 140 160 2017E 2018E 2019E $ MM D&C/Recompletions Capex

Production mix 75-85% Oil 2018 exit rate range 30,000 – 34,000 boepd Arrests production decline in 2018 and achieves production growth in 2019 Remain poised for potential future consolidation Drilling and completion capex spend 8-12 wells in 2018 and 15-20 wells in 2019 One rig deployed Q1 2018 One rig continues to drill through 2019; second rig deployed in 1H 2019 Total Capital Spend 2018 D&C $80 - $130 MM Recompletes/Workovers $5 - $15 MM P&A $50 - $70 MM Capitalized G&A, Facilities and Other $26 - $32 MM Requires additional funds from either increased pricing or new capital to maintain reasonable liquidity in 2019 Accelerated Development Scenario Outcomes 24 26,000 – 30,000 29,000 – 33,000 28,000 – 34,000 20,000 22,500 25,000 27,500 30,000 32,500 35,000 2017 Q4E 2018E 2019E BOE/ day Avg. Annual Production 33 – 35 85 – 145 155 – 215 0 50 100 150 200 250 2017E 2018E 2019E $ MM D&C/Recompletions Capex

Appendix 25

Leading Operator in GOM Shelf 26 EGC Core Properties(1) Field Operator W/I Cum. Prod. (MMBOE) West Delta 73 Energy XXI 100% 389 South Timbalier 54 Energy XXI 100% 152 South Pass 49 Energy XXI 100% 111 Main Pass 61 Energy XXI 100% 65 Ship Shoal 208 Energy XXI 100% 457 West Delta 30 Energy XXI 100% 751 South Pass 78 Energy XXI 100% 264 South Timbalier 21 Energy XXI 100% 515 EGC Non-Op 2017 Development Drilling and Recompletions Focused in Core Area 1 EGC core property data can be found in the Company’s Form 10-K for the period ended December 31, 2016

BOEM and BSEE Update 27 Excellent working relationship with BOEM and BSEE Continue to operate under the terms and proposals of our plan with the BOEM EGC has bonded its sole properties and further focused bonding efforts on expired properties and properties without a major oil company in the chain of title Proactively Addressing P&A Requirements

SEC Proved Reserves – March 31, 2017(1) 28 Reserves Category Net Oil Net NGL Net Gas Net Total PV101 MMBO MMBBL BCF MMBOE MM$ Proved Developed Producing 51.8 0.9 53.7 61.6 $304.9 Proved Developed Non-Producing 9.3 0.9 33.2 15.7 $100.8 Proved Undeveloped 26.5 0.5 30.3 32.0 $203.7 Plug and Abandon - - - - ($501.0) 1P 87.6 2.2 117.2 109.4 $108.4 Probable 45.8 1.4 122.1 67.5 $574.8 Plug and Abandon - - - - $62.6 2P 133.4 3.6 239.3 176.9 $745.9 Total 109 MMBOE Total $108 MM 1P PV-10 SEC Pricing2 Category Mix 80% Oil 1 Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of March 31, 2017 2 SEC 12 month average NYMEX pricing on March 31, 2017 was $47.62 per BBL for oil and $2.73 per MCF for natural gas, before differentials PDP 62 PDN 16 PUD 32 PDP $305 PDN $101 PUD $204 P&A ($501) Gas 18% NGL 2% Oil 80%

Strip Proved Reserves – March 31, 2017(1) 29 Reserves Category Net Oil Net NGL Net Gas Net Total PV101 MMBO MMBBL BCF MMBOE MM$ Proved Developed Producing 53.8 0.9 56.1 64.1 $457.4 Proved Developed Non-Producing 9.7 0.9 34.8 16.4 $133.9 Proved Undeveloped 27.5 0.5 31.1 33.2 $278.4 Plug and Abandon - - - - ($470.6) 1P 91.0 2.3 122.0 113.7 $399.1 Probable 47.7 1.5 124.8 70.0 $693.8 Plug and Abandon - - - - $56.0 2P 138.8 3.8 246.8 183.6 $1,148.8 Total 114 MMBOE Total $399 MM 1P PV-10 Strip Pricing2 Category Mix 80% Oil 1 Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of March 31, 2017 2 Forward strip commodity pricing averages $51.58 per BBL for oil and averages $3.33 per MCF for natural gas, for the remainder of 2017, before differentials PDP 64 PDN 16 PUD 33 PDP $457 PDN $134 PUD $278 P&A ($471) Gas 18% NGL 2% Oil 80%

Adjusted EBITDA Reconciliation 30 Adjusted EBITDA is a supplemental non‑GAAP financial. Adjusted EBITDA is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or US GAAP. EGC believes that Adjusted EBITDA is useful because it allows it to more effectively evaluate its operating performance and compare the results of its operations from period to period without regard to its financing methods or capital structure. EGC excludes items such as property and inventory impairments, asset retirement obligation accretion, unrealized derivative gains and losses, non‑cash share‑based compensation expense, non-cash deferred rent expense and restructuring and severance expense. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with US GAAP or as an indicator of its operating performance or liquidity. EGC’s computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. As required under Regulation G of the Securities Exchange Act of 1934, provided below is a reconciliation of net loss to Adjusted EBITDA, a non-GAAP financial measure. (1) The deferred rent of approximately $2 million for the three months ended September 30 and June 30, 2017, is the non-cash portion of rent which reflects the extent to which our GAAP straight-line rent expense recognized exceeds our cash rent payments Successor Three Months Ended Three Months Ended September 30, June 30, 2017 2017 Net loss $ (31,580) $ (23,643) Interest expense 3,653 3,642 Depreciation, depletion and amortization 36,066 38,661 Impairment of oil and natural gas properties (2,357) (848) Accretion of asset retirement obligations 9,892 10,050 Change in fair value of derivative financial instruments 14,346 (7,061) Non-cash stock-based compensation 3,019 2,870 Deferred rent(1) 1,930 2,016 Reorganization items (113) (3,773) Severance costs 458 2,500 Adjusted EBITDA 35,314 24,414

apetrie@energyxxi.com 713-351-0617 Al Petrie – Investor + Media Relations Coordinator