Exhibit 99.2

 

www.energyxxi.com First Quarter 2017 Earnings Conference Call May 22, 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 PV - 10 and reserve volumes reported in the final NSAI reserve report, (ii) the level of potential upside actually realized by EGC from its non - proved resource base, (iii) the effects of the departure of EGC’s senior leaders on the Company’s employees, suppliers, regulators and business counterparties, (iv) the impact of restrictions in the exit financing on EGC’s ability to make capital investments and pursue strategic growth opportunities 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.

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 1 0%. 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, whic h i s the most directly comparable U.S. GAAP financial measure . PV - 10 is not a financial measure prescribed under accounting principles genera lly 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 pot ential 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 fut ure 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 mea sure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oi l 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 permi ts the optional disclosure of probable reserves. The SEC defines "probable" reserves as "those additional reserves that are less ce rta in to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered." EGC has inclu ded 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. H owe ver, 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 incl ude d in this press release. Factors affecting ultimate recovery include the scope of EGC's ongoing drilling program, which will be direct ly affected by commodity prices, the availability of capital, regulatory approvals, drilling and production costs, availability of drilling ser vices and equipment, drilling results, lease expirations, transportation constraints and other factors; actual drilling results, includ ing geological and mechanical factors affecting recovery rates; and budgets based upon our future evaluation of risk, returns and the availabili ty of capital. With respect to commodity prices, there can be no assurance that actual oil and gas prices will be consistent with the forwar d s trip pricing case or any of the other pricing assumptions described in this press release.

First Quarter and Recent Highlights 4 • Production averaged ~41,000 BOE/d, with 71% oil • Reported strong cash and cash equivalents of $160.5 million at March 31, 2017 • Reestablished a commodity hedging program in February 2017 by entering into costless collars for 10,000 barrels of oil per day from March 2017 to December 2017 • Commenced trading on the NASDAQ Global Select Market on February 28, 2017 • Contracted a rig to begin development drilling program, with first well spudding in early June • Retained Morgan Stanley to assist with the evaluation of strategic alternatives

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 x Executive Leadership Additions • Douglas E. Brooks named Chief Executive Officer & President • Scott Heck named Chief Operating Officer • Hugh Menown named Interim Chief Financial Officer x Experienced Board of Directors with strong energy backgrounds x Extensive “safety culture” assessment completed & improvement plan initiated x 2017 development drilling program finalized, commence operations in early June x Develop oil - weighted assets with strong economics at current strip pricing x Retained Morgan Stanley to assist with strategic alternatives x Actively pursuing a range of opportunities with both public and private companies x Generated Adjusted EBITDA (1) of $43 million in Q1 2017 x ST54 capital workover and recompletion projects delivered robust economic returns x Continued implementation of LOE and G&A cost saving initiatives x 2017 CAPEX expected to be fully funded with available cash and internal cash flow x Opportunistically add hedges to protect cash flow 1 Adjusted EBITDA is a non GAAP measure, see reconciliation to net income in appendix

EGC Overview 6 Attractive Upside Optionality with Continued Recovery in Oil Prices Pure Play Gulf of Mexico Shelf Company • 109.4 MMBOE Proved Reserves • 80% Oil, 2% NGL, 18% Gas • 72% Proved Developed • 90% Operated • 258 Blocks with 57 Producing Fields • 616 Gross Producing Wells • 439,294 Net Developed Acres • 143,208 Net Undeveloped Acres • 17,000 Square Miles 3D Seismic Inventory At March 31, 2017

SEC Proved Reserves – March 31, 2017 (1) 7 Reserves Category Net Oil Net NGL Net Gas Net Total PV10 1 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 PDP 62 PDN 16 PUD 32 PDP $305 PDN $101 PUD $204 P&A ($501) Gas 18% NGL 2% Oil 80% Total 109 MMBOE Total $108 MM 1P PV - 10 SEC Pricing 2 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 dif fer entials

Strip Proved Reserves – March 31, 2017 (1) 8 Reserves Category Net Oil Net NGL Net Gas Net Total PV10 1 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 PDP 64 PDN 16 PUD 33 PDP $457 PDN $134 PUD $278 P&A ($471) Gas 18% NGL 2% Oil 80% Total 114 MMBOE Total $399 MM 1P PV - 10 Strip Pricing 2 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

Leading Operator in GOM Shelf 9 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

Production Analysis 10 BOED 2017 Capital Program Focused on Minimizing Base Decline Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Gas 14,133 14,417 12,142 12,300 10,983 NGL 2,100 1,530 1,290 530 900 Oil 32,890 31,390 31,190 29,615 29,100 Total 49,133 47,347 44,632 42,455 40,993 49,133 47,347 44,632 42,455 40,993 - 10,000 20,000 30,000 40,000 50,000 60,000 71% 70% 70% 66% 67% Q12016 to Q12017 • Oil production decline ~12% • Focused on oil workover and recompletions projects • Total production decline ~17%

Lease Operating & Gathering 11 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Gathering and Transportation $14.2 $10.0 $14.1 $5.5 $21.7 Workover/Maintenance $12.1 $17.5 $11.0 $11.7 $10.0 Direct LOE/Insurance $69.9 $63.6 $57.8 $63.2 $65.1 Total $96.2 $91.1 $82.9 $80.4 $96.8 $96.2 $91.1 $82.9 $80.4 $96.8 $- $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $MM 2017 Focus on Cost Reduction and Optimization Savings in Multiple Categories (1) 1) Q216 Gathering and Transportation included ~$3MM credit related to ONRR refund Q416 Gathering and Transportation included ~$8MM credit related to ONRR refund (1) 2016 quarterly adjusted run rate for LOE and Gathering ~$90 million • Q1 2017 Restored normalized base operational spending and completed over 100 workover and maintenance projects • Q1 2017 Gathering and Transportation higher due to added expense inclusion and pipeline storage facility repairs

Margin Analysis 12 12 $/BOE $19.65 $17.58 $23.57 $1.33 $3.00 $2.71 $5.79 $3.10 $4.79 $15.03 $(4.97) $15.51 $11.76 $(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 LOE/Insurance/Transportation Workover/Maintenance Net G&A Interest Margin Cost Control and Interest Elimination Drives Down Breakeven and Increases Cash Flow in a Rising Commodity Price Environment 1) Q1 2017 Net G&A excludes severance and restructuring costs (1)

13 Crude Hedge Profile FY2017 Weighted Average Prices ($/Bbl) Volume Sub - floor Floor Ceiling Mbbls March $52.30 $57.43 310 April – June $52.30 $57.43 910 July – Sept. $52.30 $57.43 920 Oct. – Dec. $52.30 $57.43 920 Full Year 3,060 Hedges Initiated to Protect Capital Spend and Cash Flow 0 2,000 4,000 6,000 8,000 10,000 12,000 March 17 Q2 Q3 Q4 BOPD Fiscal Year 2017 LLS Collars • Re - established a commodity hedging program in February 2017 for 10,000 BOPD for the period from March 2017 to December 2017 • Manages commodity price risk and enhances cash flow certainty and predictability • Opportunistically looking to add additional oil contracts

2017 Preliminary Capital Budget 2017 Capital Program Funded with Internally Generated Cash Flow and Available Cash 14 • Estimated Capital: $140 - $170 million – Includes Abandonment Costs of $50 - $70 million • 2017 Development Drilling Program – Commencing mid - year – Two to four development wells planned in core area – 100% working interest – >40 identified development drilling locations • 2017 Recompletion Program – Currently underway – 1Q17 complex two well program at ST54 yielded strong economic returns and >1,000 BOEPD – ~15 recompletions planned – >100 identified recompletion locations

Liquidity – March 31, 2017 15 (1) Does not include restricted cash of $57MM which consists of collateral related to bonding and escrow accounts (2) Primarily to secure ExxonMobil plug and abandonment obligations (3) Subject to restrictions under credit facility terms $MM Cash & Cash Equivalents (1) $160 Credit Facility $290 Less: Amount Drawn ( $74) Less: Letter of Credit Utilization (2) ($203) Total Available within Credit Facility (3) $13 Total Liquidity $173

Renewed Focus 16 Strategic Alternative Review Process Underway to Unlock the Value of our Resource Base Utilizing Our Strong Balance Sheet • New Management Team – Continued commitment to HSE excellence – Highly experienced technical and financial team – Focused on maximizing value for shareholders • Strong Financial Discipline – Liquidity of $173 million at March 31, 2017 – Adjusted EBITDA (1) $43 million in Q1 2017 – Established hedging to protect cash flow • Near - term Focus on Low - Risk Exploitation – Highly economic recompletions – Continued development from existing platforms • Continue Proactively Addressing P&A Responsibilities 1 Adjusted EBITDA is a non GAAP measure, see reconciliation to net income in appendix

APPENDIX 17

BOEM and BSEE Update 18 • 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

Three Months Ended March 31, 2017 Net Loss $ (65,315) Interest expense 3,834 Depreciation, depletion and amortization 42,006 Impairment of oil and natural gas properties 44,054 Accretion of asset retirement obligations 12,397 Change in fair value of derivative financial instruments (3,409) Non-cash stock-based compensation 852 Deferred rent (1) 2,015 Severance and restructuring costs 6,200 Adjusted EBITDA $ 42,634 Adjusted EBITDA Reconciliation 19 Adjusted EBITDA is a supplemental non - GAAP financial. Adjusted EBITDA is not a measure of net income or cash flows as determine d 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 accr eti on, unrealized derivative gains and losses, non - cash share - based compensation expense, non - cash deferred rent expense and restructuring and sev erance expense. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows fro m o perating activities as determined in accordance with US GAAP or as an indicator of its operating performance or liquidity. EGC’s compu tat ions 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 Adju ste d EBITDA, a non - GAAP financial measure. (1) The deferred rent of approximately $2 million is the non - cash portion of rent which reflects the extent to which our GAAP st raight - line rent expense recognized exceeds our cash rent payments

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