Investor Presentation April 2018 www.energyxxi.com - - PowerPoint PPT Presentation

www.energyxxi.com

Investor Presentation

April 2018

www.energyxxi.com

Fortifying & Enhancing Our Position

energy xxi gulf coast, inc.

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 that could cause actual results to differ materially from the projections, anticipated results or other expectations expressed. It is not possible to predict or identify all such factors and the following list of factors should not be considered a complete statement of all potential risks and uncertainties, including, but not limited to: (i) 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; (ii) our new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value could vary significantly from current or future estimates; (iii) our future financial condition, results of operations, revenues, expenses and cash flow; (iv) our current or future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern; (v) the effects of the departure of our senior leaders and the hiring of a new senior management team on our employees, suppliers, regulators and business counterparties; (vi) recent changes in the composition of our board of directors; (vii) our inability to retain and attract key personnel; (viii) our ability to post collateral for current or future bonds or comply with any new regulations or Notices to Lessees and Operator; (ix) our ability to comply with covenants under the three-year secured credit facility; (x) changes in our business strategy; (xi) sustained or further declines in the prices we receive for our oil and natural gas production; and (xii) 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2017 filed by EGC for more information. While EGC makes these statements and projections in good faith, EGC assumes no obligation and expressly disclaims any duty to update the information contained herein except as required by law.

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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

• perating 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 December 31, 2017 with each category of reserves estimated in accordance with SEC guidelines and definitions. The SEC permits the

• ptional 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

• presentation. 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 presentation.

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4

Highlights and Recent Key Items

Full Year 2017 Highlights

• Reported clean balance sheet with cash and cash equivalents of $152 million at December 31, 2017
• Implemented significant G&A and LOE cost saving initiatives
• Initiated transformative operational plans which continue into 2018

Fourth Quarter 2017 and Recent Key Items

• Produced ~27,600 BOE per day, of which 77% was oil, and within the Company’s guidance range
• Benefited from strong oil price realizations during the fourth quarter of $59.27 per barrel (before the

impact of derivatives), approximately 7% higher than the WTI average price of $55.40 per barrel for the quarter

• Incurred a net loss of $215.1 million which included a non-cash ceiling test impairment charge of

$145.1 million related to the decrease in SEC proved reserves and the present value of those SEC proved reserves discounted at 10% (“PV-10 Value”) and a loss on financial derivatives of $33.3 million

• Announced total 2018 capital expenditures budget in the range of $145 to $175 million
• High Tide well at West Delta 30 field, as expected, transitioned to ~1,000 barrels of oil and ~2.0 MMCF

per day currently

• Plans to spud the first development well of the 2018 drilling program, the West Delta 73 C-27 McCloud

in March

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 Our #1 Priority is the Protection of Our Employees, Contractors and the Environment  Maintain Strong Working Relationship with BOEM & BSEE

Pivotal Points Driving Success for 2018+

 Completed Strategic Review Process  Developed Sustainable Stand-alone Plan  Implemented Significant Cost Savings  Aligning Operational Costs with EGC’s Forecasted Needs  Commitment to Financial Discipline  Seasoned Board of Directors & Management Team

• Gary C. Hanna named Chairman of the Board on March 29, 2018

 Experienced Leadership Driving New Culture  Realigned EGC Core Values, Mission And Vision  2018 Drilling Program Focused on Core Operating Area Includes Two Development Wells, Two Water Injection Wells and Two Exploitation Wells  Commence Drilling of WD-73 McCloud in March  Pursue Acquisitions and be Receptive to GOM Consolidation Transactions

Transitional Year 2017 Transformative Year 2018 Committed to Safety & the Environment Financially Disciplined Creating Value

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Core Values

Safety and Environment

Safety Without Compromise

• Every Job,

Every Day

Relationships

People are

• ur greatest

assets

Integrity

We create an atmosphere that fosters trust, honesty, and transparency

Accountability

We are committed to the success

• f our

Company, we take

• wnership in

everything we do

Innovation

We empower

• ur people to

challenge the status quo every day

Community

We have a social responsibility to the communities in which we live and work.

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Excellence in Safety and Environmental Stewardship Are Top Priorities That Guide Our Decision Making and Risk Management.

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energy xxi gulf coast, inc.

 Leverage Our Operational, Technical and Commercial Expertise in Conventional Oil and Gas Assets both Offshore and Onshore  Grow Value by Developing and Exploiting Our Considerable 2P and 3P Reserves and Resource Potential  Target Acquisitions Where We Can Deploy Our Expertise and Optimize Our Portfolio  Continue to Investigate/Implement Cost Controls in All Aspects of Our Business

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Strategy Based on Core Competencies

EGC’s Mission is to Become a Top Quartile E&P Company in Basins Where We Operate

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Near-Term Tactics

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Execute 2018 Development & Exploitation Program Optimize 2019 Drilling Program & Seek Needed Capital Pursue Offshore & Onshore Acquisition Opportunities Rationalize & Optimize Portfolio Remain Receptive to Potential GOM Consolidation Transactions

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energy xxi gulf coast, inc.

EGC Portfolio

Attractive Upside Optionality with Continued Recovery in Oil Prices

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Summary

• Oil-Weighted Asset Base

− Year-End Proved Reserves were 84% Oil

• Operator in the GOM since 2006
• Currently concentrated on the GOM Shelf
• 155 Blocks with 55 Producing Fields

̵ 577 Gross Producing Wells ̵ 421,974 Net Developed Acres ̵ 57,346 Net Undeveloped Acres

• Seismic Inventory

− 17,000 Square Miles 3D Seismic Inventory

• Publically traded on Nasdaq exchange

− Ticker: EGC

14% 2% 84%

(1) NSAI prepared reserves at December 31, 2017

Proved Reserves(1) :

88.2 MMBOE 21% 2% 77% 27,600 BOED

4Q17 Production:

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energy xxi gulf coast, inc.

Focused on Operational Excellence

• EGC Safety Motto

− Safety without Compromise – Every Job, Every Day

• Cost steering committee formed with focus on identifying and safely 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 ̵ Sole sourcing items such as labor and chemicals

• Production optimization

̵ Integrity management – increase preventive maintenance projects ̵ Reliability management – improve downtime performance ̵ Portfolio management – PDP/PDN assessment and execution

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WD 31 “High Tide” Drill Well

2017 Drill Well Outperforming Pre-Drill Forecast

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C4 Sand Structure

L

WD 31 L-14 ST2 High Tide

C4

BF2

200 400 600 800 1,000 1,200 2,000 4,000 6,000 8,000 10,000 12,000 1-Sep-17 1-Oct-17 1-Nov-17 1-Dec-17 1-Jan-18 1-Feb-18 1-Mar-18 1-Apr-18 1-May-18 Oil Production (bo/d) Gas Production (Mcf/d)

Gross Daily Gas (Mcf/d) Gross Daily Oil (bo/d)

Gas Cap Production Oil Rim Production

• WD 31 L-14 ST2 High Tide well was successfully drilled to a

total depth of 9,542’ MD from WD 31 L Platform

• Actual drill and completion costs were lower than the total

pre-drill AFE cost estimate, despite prolonged completion activities caused by gulf storms – Pre-drill: $5.4 MM drill and $4.7 MM complete – Post-drill: $3.4 MM drill and $5.5 MM complete

• Both targets found at their expected locations, were thicker

than expected, and logged attic gas caps, as predicted

• C4 Sand completion initially produced gas cap and recently

began producing the oil rim, as predicted – 4/2/2018 well test: 1,019 bo/d + 1.935 Mcf/d – Cumulative to date: 24 Mbo + 583 MMcf

• Expected Gross Volumes by Zone:

– C4 Sand: 365 Mbo + 1,000 MMcf (532 Mboe) – BF2 Sand: 236 Mbo + 391 MMcf (301 Mboe) Nasdaq: EGC

energy xxi gulf coast, inc.

2018 Drilling Program

Executable Program in Our Core Operating Area

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• 6 Drill Wells
• 2 Development wells
• 2 Water Injection well
• 2 Exploitation wells
• These injection wells are designed

to potentially increase field production or maintain reservoir pressure (not disposal wells)

• 7-9 Recompletions

EGC Core Operating Area Focused Drilling Program

Drill Well #1

West Delta 73 McCloud

Spud: March 2018

TD: ~9,370’ WD: ~175’ Development 100% W/I

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energy xxi gulf coast, inc.

WD 73 McCloud PUD Well

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Structure Map – F-40 Sand WD 73 C-15 ST03 (HEMAN DUAL)

F-40 Sand

WD 73 WD 92 WD 74 WD 91 HE-MAN C-15ST3

C

F-45 Sand

McCLOUD

OOWCavg -8,265’ COWCavg -8,208’

West Delta 73 Field Stats

• Discovered 1962 by Humble, located in ~175’ WD
• Cumulative Production(1): >392 MMBOE
• Infrastructure: 6 production structures and 27 active

wells in the field

Overview

• Working Interest: 100%
• Spud Date: March 2018
• Estimated D&C Cost: $8 - $12 MM
• Directional dual well targeting the F-40 and F-45

sands.

• Should capture attic area updip of current producers

in the F-40 sand;

• Should capture reserves in between Sabinal and

He-man producers in the F-45 sand

• Drilling directional well from WD 73-C Platform

(1) Cumulative production through 11/2017 for entire West Delta 73 OCS field per OWL (not only EXXI acreage)

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South Timbalier 54 Field Stats

• Discovered 1955 by Humble, located in

~67’ WD

• Cumulative Production(1): >153 MMBOE
• Infrastructure: 7 production structures and 27 active

wells in the field.

Overview

• Working Interest: 100%
• Probability of Success : 76%
• Anticipated Spud Date: August 2018
• Estimated D&C Cost: $8 - $12 MM
• Directional Well Targeting I-20 Sand
• Prospect is a downthrown fault closure supported by a

seismic amplitude anomaly

• A similar I-20 sand amplitude anomaly in the adjacent

fault block to the south has produced 556 MBO & 1.9 BCF to date from the #J-5 well

• Drill deviated well from ST 54 G Platform (existing

platform)

• Gross Unrisked reserve potential: 900 to 1,200 MBOE

ST 54 Koala Exploitation Well

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Structure Map – I-20 Sand Log Section – ST 54 #J-5 I-20 Sand

I-20 Sand 90’ Net Oil

(1) Cumulative production through 11/2017 for entire South Timbalier 54 OCS field per OWL (not only EXXI acreage)

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energy xxi gulf coast, inc.

WD 30 Warthog Exploitation Well

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Structure Map & Amplitude – D4 Sand Log Section – P42 D4 Sand

D4 Sand 180’ TVT

Cum production: 1.6 MMBO, 2.6 BCF Fault

West Delta 30 Field Stats

• Discovered 1948 by Humble, located in

~45’ WD

• Cumulative Production(1): >752 MMBOE
• Infrastructure: 45 production structures and 80 active

wells in the field.

Overview

• Working Interest: 100%
• Probability of Success: 77%
• Anticipated Spud Date: December 2018
• Estimated D&C Cost: $8 - $12 MM
• Directional Well Targeting D4 Sand
• Test amplitude-supported D4 sand that is fault-

separated from pod which produced 1.6 MMBO and 2.6 BCF

• Producing sands on the southeast flank of the WD30

salt dome in optimal location

• Drill deviated well from WD29 J platform (existing

platform)

• Gross Unrisked reserve potential: 500 to 700 MBOE

(1) Cumulative production through 11/2017 for entire West Delta 30 OCS field per OWL (not only EXXI acreage)

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• Estimated Capital: $145 - $175 million

– Anticipates drilling six new wells: $55 - $65 million – Facility improvements: $10 - $15 million – Performing 7-9 recompletions: $8 - $10 million – P&A projects: $50 - $60 million – Capitalized G&A: $18 - $22 million – Seismic & Other: $3 - $4 million

• Future Drilling and Recompletion Potential

– >50 identified future drilling locations – >100 identified recompletion locations

2018 Capital Budget

2018 Capital Program Expected to Contribute to Arresting Production Decline

D&C 37% Facility 8% Recompletions 6% P&A 35% Capitalized G&A 13% Seismic & Other 1%

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energy xxi gulf coast, inc.

EGC SEC Reserves – Year-End 2017

(1)

PDP 56.1 PDN 10.1 PUD 22.0 Gas 14% NGL 2% Oil 84%

Total 88.2 MMBOE

Category Mix

84% Oil

1 Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of December 31, 2017, including proved, probable and possible

Reserves Category Net Oil Net NGL Net Gas Net Total MMBO MMBBL BCF MMBOE Proved Developed Producing 48.8 0.7 39.5 56.1 Proved Developed Non-Producing 6.2 0.6 19.4 10.1 Proved Undeveloped 19.4 0.3 14.1 22.0 1P 74.4 1.7 73.0 88.2 Probable 45.8 1.8 124.6 68.4 2P 120.2 3.5 197.6 156.6 Possible 32.2 0.9 66.3 44.2 3P 152.4 4.4 263.8 200.7

17 SEC 12 month average NYMEX pricing on 12-31-2017: $47.79 per BBL and $2.98 per MCF, before differentials

energy xxi gulf coast, inc.

EGC Forward Strip Reserves – 1-26-18

(1)

PDP 58.3 PDN 10.6 PUD 23.2 Gas 14% NGL 2% Oil 84%

Total 92.1 MMBOE

Category Mix

84% Oil

Reserves Category Net Oil Net NGL Net Gas Net Total MMBO MMBBL BCF MMBOE Proved Developed Producing 50.8 0.7 40.6 58.3 Proved Developed Non-Producing 6.7 0.6 19.7 10.6 Proved Undeveloped 19.7 0.6 17.3 23.2 1P 77.3 1.9 77.5 92.1 Probable 47.3 1.6 121.7 69.1 2P 124.5 3.5 199.2 161.2 Possible 33.5 0.9 65.9 45.3 3P 158.0 4.4 265.2 206.6

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(1) Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of December 31, 2017, including proved, probable and possible

Forward strip pricing on 1-26-2018: $58.99 per BBL and $2.95 per MCF, before differentials

energy xxi gulf coast, inc.

SEC and Strip Pricing PV10

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$0 $200 $400 $600 $800 $1,000 $1,200 $1,400 $1,600 1P 2P 3P SEC Pricing $15 $614 $1,119 Strip Pricing $323 $1,003 $1,555

$MM

Significant Improvement in PV10 With Increasing Oil Prices

12/31/17 SEC Pricing: $47.79/BBL, $2.98/MCF 1/26/18 Strip Pricing: $58.99/BBL, $2.95/MCF

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Changes in SEC Reserves 3-31-17 to 12-31-17

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• Reductions include

̵ (8.8) MMBOE for production from March 31 to December 31, 2017 ̵ (7.3) MMBOE due to higher estimated LOE costs ̵ (5.3) MMBOE for reserve write

• ffs primarily due to 5 year PUD

drilling rule ̵ (5.0) MMBOE in revisions, 80%

• f which were gas reserves
• Increases include

̵ 4.5 MMBOE due to improved pricing ̵ 0.7 MMBOE due to additions and lower capital cost assumptions

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Production History

BOED

Forecasting Production Stabilization in 2018 with Increased Drilling

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018E Gas 10,983 8,150 6,700 5,750 5,500 NGL 900 1,000 800 600 600 Oil 29,100 26,800 25,100 21,300 20,400 Total 40,983 35,950 32,600 27,650 26,500 40,983 35,950 32,600 27,650 26,500 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000

75% 77% 77% 77% 70%

• 4Q 17 vs. 3Q 17 declined due

to:

̵ Disruptions due to: ̵ Hurricane Nate and other weather-related issues that, in total, reduced volumes about 4,000 BOE per day. ̵ Production equipment maintenance, incremental pipeline and facility related unscheduled downtime ̵ Quarter-to-quarter natural declines

• Continued focus on low cost

workover and recompletion projects

• 2018 Forecasted exit rate:

28,000 – 30,000

Production Benefits from Premium HLS/LLS Pricing, Which is Forecasted in 2018 to be $2.50/BBL

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Guidance Midpoint

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energy xxi gulf coast, inc.

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018E Workover/Maintenance $10.0 $13.4 $8.5 $12.3 $11.5 Insurance $6.3 $7.1 $5.0 $5.1 $5.0 Direct Loe $61.0 $63.2 $64.3 $63.4 $65.0 Total $77.3 $83.7 $77.8 $80.8 $81.5

$77.3 $83.7 $77.8 $80.8 $81.5

$- $10.0 $20.0 $30.0 $40.0 $50.0 $60.0 $70.0 $80.0 $90.0

$MM

Direct LOE, Insurance and Workovers

Continued Focus on Sustainable Cost Reduction and Optimization Savings in Multiple Categories While Maintaining Safety of Operations

• Go forward cost savings

initiatives:

̵ Sole sourcing items such as labor and chemicals ̵ Supply chain management, reduction

• f third party costs and
• perating efficiency

improvements ̵ Consolidated Grand Isle and Port Fourchon shore base facilities

• Negotiated and realized a

lower insurance rate

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Guidance Midpoint

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energy xxi gulf coast, inc.

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Pipeline Facility Fee $10.5 $10.5 $10.5 $10.5 $10.5 Gathering&Transportation $11.2 $2.7 $(2.4) $10.2 $8.5 Total $21.7 $13.2 $8.1 $20.7 $19.0 $21.7 $13.2 $8.1 $20.7 $19.0 $(5.0) $- $5.0 $10.0 $15.0 $20.0 $25.0 $MM

Pipeline Facility Fee Gathering & Transportation

1) Includes Gathering and Transportation credits related to ONRR refunds for the following quarters: Q217 ~$5MM, Q317 ~$11MM

• Pipeline Facility Fee flat

$10.5 MM quarterly

• Gathering and

Transportation past fluctuations due to: − ONRR refunds in Q2 2017 ~$5 MM and Q3 2017 ~$11 MM

• ONRR Lookback process

continues

• No additional material ONRR

refunds forecasted

(1) (1)

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Guidance Midpoint

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energy xxi gulf coast, inc.

G&A Expenses

$20.7 $17.8 $12.0 $12.0 $12.3 $0.9 $2.9 $3.0 $2.7 $2.7 $- $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018E $MM Cash G&A Non-Cash G&A

• Q1 2018 costs 31% below

Q1 2017

• EGC realized $8 MM of

annualized G&A savings due to reduced staffing from Q1 to Q4 2017

• 2017 included $7.9 MM

related to severance costs in addition to restructuring, reorganization and bankruptcy emergence charges

Adjusting Staff Levels and Costs to Better Align with Operational Plan

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Guidance Midpoint

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energy xxi gulf coast, inc.

$- $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $50 $60 $70

$30.52 $30.52 $30.52 $7.19 $7.19 $7.19 $4.89 $4.89 $4.89 $2.19 $10.13 $18.08

$/BOE

Total LOE Total G&T G&A Operating Cash Margin

(4,5)

2018 Operational Cash Flow

Each $1/BBL Improvement in Oil Price Should Increase Annual Cash Flow $7-$9 MM

• Midpoint of 2018 production guidance:

28,000 BOEPD

• Midpoint of 2018 cost guidance used for Total

LOE, Total G&T and G&A

• To adjust Operating Cash Margin for 2018

hedging: $50 WTI – $0.40/BOE increment $60 WTI – ($3.20/BOE) reduction $70 WTI – ($6.90/BOE) reduction

• Theoretical EBITDA at midpoint of 2018

production guidance with hedging: $50 WTI – $ 25 - $ 30 MM $60 WTI – $ 65 - $ 75 MM $70 WTI – $110 - $120 MM

• 2018 Forecasted exit rate:

28,000 – 30,000 BOEPD

Unhedged WTI Oil Price

(1) Includes direct LOE, WO/Maintenance, Insurance & Prod Taxes (2) Includes gathering & transportation and pipeline facility fee

(3) (1) (2)

3) Excludes non-cash compensation 4) Includes forecasted $2.50/BBL of HLS/LLS differential premium 5) Excludes Interest and Capex expenses

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energy xxi gulf coast, inc.

$- $10.00 $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 $50 $60 $70

$26.69 $26.69 $26.69 $6.29 $6.29 $6.29 $4.28 $4.28 $4.28 $7.53 $15.48 $23.42

$/BOE

Total LOE Total G&T G&A Operating Cash Margin

(4,5)

2019 Scenario with Enhanced Drilling

Optimized 2019 Scenario Would Yield Substantial Improvement in Results Assuming Additional Capital Available to Fund Program

• This is not forward guidance, but a

scenario based on the assumptions listed below

• Enhanced drilling scenario 2019

production forecast: 32,000 BOEPD

• Forecasted 2019 absolute cost flat vs.

2018 for Total LOE, Total G&T and G&A

• No hedges currently in place for 2019
• Theoretical EBITDA at midpoint of 2019

production guidance:

$50 WTI – $85 - $95 MM $60 WTI – $170 - $190 MM $70 WTI – $265 - $285 MM

• Potential production exit rate:

32,000 – 36,000 BOEPD

Unhedged WTI Oil Price

(1) Includes direct LOE, WO/Maintenance, Insurance & Prod Taxes (2) Includes gathering & transportation and pipeline facility fee

(3) (1) (2)

3) Excludes non-cash compensation 4) Includes forecasted $2.50/BOE of HLS/LLS differential premium 5) Excludes Interest and Capex expenses

Enhanced drilling includes several high impact exploitation wells driving production increases

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energy xxi gulf coast, inc.

Liquidity Profile

December 31, 2017 $MM Total Cash & Cash Equivalents(1) $152 Exit Credit Agreement $290 Less: Amount Drawn ( $74) Less: Letter of Credit Utilization(2) ($203) Total Available Credit Facility(3) $13 Total Liquidity $165

(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.

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energy xxi gulf coast, inc.

Crude Hedge Profile (As of 03/16/18)

• Currently Hedged
• 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

2,000 4,000 6,000 8,000 10,000 12,000 14,000

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 WTI Swaps LLS Swaps Brent Swaps

Current Hedge Profile 2018

Strategy: Hedge Opportunistically to Support the Base Business

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energy xxi gulf coast, inc.

Full Year 2018 Guidance (As of 03/16/18)

(1) Production is priced 60-70% HLS; 30-40% LLS (2) Reflects impact of curtailments due to weather & other

26,000 - 27,000 BOEPD(2) Production(1) $60 - $70 MM Direct LOE $10 - $13 MM Workover/Maintenance $4 - $6 MM Insurance $7 - $10 MM Gathering & Transportation $10 - $11 MM Pipeline Facility Fee $14 - $16 MM General & Administrative $30 - $35 MM DD&A $9 - $11 MM Accretion of ARO $35 - $45 MM Capital Expenditures(4) 26,000 - 30,000 BOEPD(3) $235 - $255 MM $40 - $50 MM $18 - $23 MM $28 - $35 MM $41 - $43 MM $55 - $65 MM $120 - $130 MM $36 - $44 MM $145 - $175 MM Q1 2018 Full Year 2018

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(4) Full Year 2018 Capex consists of D&C capex ~$65-$75 MM; P&A capex ~$50-$60 MM; and Facility upgrades and optimization - $10 – $15 MM

(3) Forecast exit rate: 28,000 – 30,000 BOEPD

energy xxi gulf coast, inc.

Factors Impacting EGC’s Future

Outlook For EGC In 2018 And Beyond Is Rapidly Improving

Highly Leveraged to Increasing Oil Prices Premium Realizations vs. WTI Large Legacy Fields with Upside Potential Underutilized Infrastructure Enhances Opportunity with Low Incremental Costs Further Develop a High Performing Management and Technical Team Fiscally Driven Board with Significant Expertise in Oil and Gas Strong and Clean Balance Sheet Well Positioned for Future GOM Consolidation

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Execute Stand Alone Plan & Pursue Acquisitions

Nasdaq: EGC

energy xxi gulf coast, inc.

Appendix

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Nasdaq: EGC

energy xxi gulf coast, inc.

Leadership Team

Strong, Proficient Executive Leadership With A Seasoned Board

Douglas E. Brooks – Chief Executive Officer & President

̵ Formerly CEO of Yates Petroleum and CEO of Aurora Oil & Gas ̵ 24 years of service with Marathon Oil Company ̵ B.S. in Management University of Wyoming and MBA Finance Our Lady of the Lake University

Scott Heck – Chief Operating Officer

̵ Formerly COO of Bennu Oil & Gas and SVP Global Offshore E&P of Hess Corporation ̵ 25 years of service with Hess Corporation ̵ B.S. in Petroleum Engineering Marietta College

TJ Thom Cepak – Chief Financial Officer

̵ Formerly CFO of KLR Energy and CFO of EPL Oil & Gas ̵ 14 years of service with EPL Oil and Gas and 8 years of service with Exxon ̵ B.S. in Engineering University of Illinois and MBA Finance Tulane University

25 years experience 27 years experience 37 years experience 34 years experience

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Marguerite Woung-Chapman – Senior Vice President, General Counsel

̵ Formerly SVP, GC of EP Energy ̵ 20+ years of service with El Paso Corporation ̵ B.S. in Linguistics Georgetown University and J.D. Georgetown University Law Center

Nasdaq: EGC

energy xxi gulf coast, inc.

Adjusted EBITDA Reconciliation

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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.

Successor Three Months Three Months Ended Ended Year Ended December 31, September 30, December 31, 2017 2017 2017

Net loss $ (215,069) $ (35,157) $ (341,010) Interest expense 3,707 3,653 14,836 Depreciation, depletion and amortization 33,439 36,131 150,151 Accretion of asset retirement obligations 9,962 9,753 42,780 Impairment of oil and natural gas properties 145,086

—

185,860 Change in fair value of derivative financial instruments 28,691 14,346 32,567 Non-cash stock-based compensation 2,745 3,019 9,486 Deferred rent(1) 1,930 1,930 7,891 Severance costs 325 458 7,904 Adjusted EBITDA $ 10,816 $ 34,133 $ 110,465

1) The deferred rent of approximately $1.9 million, $1.9 million and $7.9 million for the three months ended

December 31, 2017, three months ended September 30, 2017 and the year ended December 31, 2017, respectively, 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.

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energy xxi gulf coast, inc.

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Al Petrie Investor + Media Relations Coordinator apetrie@energyxxi.com (713) 351-3171 Energy XXI Gulf Coast, Inc. 1021 Main Street Suite 2626 Houston, Texas 77002 Argelia Hernandez Investor + Media Relations Specialist ahernandez@energyxxi.com (713) 351-3175