Investor Presentation

Transcription

1 Fortifying & Enhancing Our Position Investor Presentation April

2 Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 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. 2

3 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 December 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 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. 3

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 4

5 Pivotal Points Driving Success for Transitional Year 2017 Transformative Year 2018 Committed to Safety & the Environment Completed Strategic Review Process Developed Sustainable Stand-alone Plan 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 Our #1 Priority is the Protection of Our Employees, Contractors and the Environment Maintain Strong Working Relationship with BOEM & BSEE Financially Disciplined Creating Value Implemented Significant Cost Savings Aligning Operational Costs with EGC s Forecasted Needs Commitment to Financial Discipline 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 5

6 Core Values Safety and Environment Relationships Integrity Accountability Innovation Community Safety Without Compromise - Every Job, Every Day People are our greatest assets We create an atmosphere that fosters trust, honesty, and transparency We are committed to the success of our Company, we take ownership in everything we do We empower our people to challenge the status quo every day We have a social responsibility to the communities in which we live and work. Excellence in Safety and Environmental Stewardship Are Top Priorities That Guide Our Decision Making and Risk Management. 6

7 Strategy Based on Core Competencies 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 EGC s Mission is to Become a Top Quartile E&P Company in Basins Where We Operate 7

8 Near-Term Tactics 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 8

9 EGC Portfolio 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 Seismic Inventory 577 Gross Producing Wells 421,974 Net Developed Acres 57,346 Net Undeveloped Acres 17,000 Square Miles 3D Seismic Inventory Publically traded on Nasdaq exchange Ticker: EGC 4Q17 Production: 21% 2% 77% Proved Reserves (1) : 2% 14% 84% 27,600 BOED 88.2 MMBOE Attractive Upside Optionality with Continued Recovery in Oil Prices (1) NSAI prepared reserves at December 31,

10 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 10

11 WD 31 High Tide Drill Well 2017 Drill Well Outperforming Pre-Drill Forecast 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 WD 31 L-14 ST2 High Tide BF2 C4 Sand Structure L Both targets found at their expected locations, were thicker than expected, and logged attic gas caps, as predicted C4 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 Mcf/d Cumulative to date: 24 Mbo MMcf Expected Gross Volumes by Zone: C4 Sand: 365 Mbo + 1,000 MMcf (532 Mboe) BF2 Sand: 236 Mbo MMcf (301 Mboe) Gas Production (Mcf/d) 12,000 10,000 8,000 6,000 4,000 2,000 Gross Daily Gas (Mcf/d) Gross Daily Oil (bo/d) Gas Cap Production Oil Rim Production 1,200 1, Oil Production (bo/d) 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 11

12 2018 Drilling Program Focused Drilling Program 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) EGC Core Operating Area 7-9 Recompletions Drill Well #1 West Delta 73 McCloud Spud: March 2018 TD: ~9,370 WD: ~175 Development 100% W/I Executable Program in Our Core Operating Area 12

13 WD 73 McCloud PUD Well 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 Structure Map F-40 Sand C COWC avg -8,208 McCLOUD WD 73 WD 92 HE-MAN C-15ST3 WD 74 WD 91 WD 73 C-15 ST03 (HEMAN DUAL) OOWC avg -8,265 F-40 Sand F-45 Sand (1) Cumulative production through 11/2017 for entire West Delta 73 OCS field per OWL (not only EXXI acreage) 13

14 ST 54 Koala Exploitation Well 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 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) 14

15 WD 30 Warthog Exploitation Well 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. Structure Map & Amplitude D4 Sand Fault Cum production: 1.6 MMBO, 2.6 BCF 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 faultseparated 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 Log Section P42 D4 Sand D4 Sand 180 TVT (1) Cumulative production through 11/2017 for entire West Delta 30 OCS field per OWL (not only EXXI acreage) 15

16 2018 Capital Budget 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 P&A 35% Seismic & Other 1% Capitalized G&A 13% D&C 37% Seismic & Other: $3 - $4 million Future Drilling and Recompletion Potential >50 identified future drilling locations >100 identified recompletion locations Facility 8% Recompletions 6% 2018 Capital Program Expected to Contribute to Arresting Production Decline 16

17 EGC SEC Reserves Year-End 2017 (1) Category Total 88.2 MMBOE Mix 84% Oil PUD 22.0 Gas 14% NGL 2% PDN 10.1 PDP 56.1 Oil 84% Reserves Category Net Oil Net NGL Net Gas Net Total MMBO MMBBL BCF MMBOE Proved Developed Producing Proved Developed Non-Producing Proved Undeveloped P Probable P Possible P SEC 12 month average NYMEX pricing on : $47.79 per BBL and $2.98 per MCF, before differentials 1 Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of December 31, 2017, including proved, probable and possible 17

18 EGC Forward Strip Reserves (1) Total 92.1 MMBOE PUD 23.2 Category Mix 84% Oil Gas 14% NGL 2% PDN 10.6 PDP 58.3 Oil 84% Reserves Category Net Oil Net NGL Net Gas Net Total MMBO MMBBL BCF MMBOE Proved Developed Producing Proved Developed Non-Producing Proved Undeveloped P Probable P Possible P Forward strip pricing on : $58.99 per BBL and $2.95 per MCF, before differentials (1) Independently engineered reserves report prepared by Netherland Sewell & Associates, Inc. ("NSAI") as of December 31, 2017, including proved, probable and possible 18

19 SEC and Strip Pricing PV10 $MM $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 1P 2P 3P SEC Pricing $15 $614 $1,119 Strip Pricing $323 $1,003 $1,555 12/31/17 SEC Pricing: $47.79/BBL, $2.98/MCF 1/26/18 Strip Pricing: $58.99/BBL, $2.95/MCF Significant Improvement in PV10 With Increasing Oil Prices 19

20 Changes in SEC Reserves to 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 offs primarily due to 5 year PUD drilling rule (5.0) MMBOE in revisions, 80% of which were gas reserves Increases include 4.5 MMBOE due to improved pricing 0.7 MMBOE due to additions and lower capital cost assumptions 20

21 Production History BOED 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 40,983 70% 35,950 32,600 27,650 Guidance Midpoint 26,500 75% 77% 77% 77% 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 0 Q Q Q Q Q1 2018E Gas 10,983 8,150 6,700 5,750 5,500 NGL 900 1, Oil 29,100 26,800 25,100 21,300 20,400 Total 40,983 35,950 32,600 27,650 26,500 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 Forecasting Production Stabilization in 2018 with Increased Drilling 21

22 Direct LOE, Insurance and Workovers $90.0 $80.0 $70.0 $77.3 $83.7 $77.8 Guidance Midpoint $80.8 $81.5 Go forward cost savings initiatives: Sole sourcing items such as labor and chemicals $MM $60.0 $50.0 $40.0 $30.0 Supply chain management, reduction of third party costs and operating efficiency improvements $20.0 $10.0 Consolidated Grand Isle and Port Fourchon shore base facilities $- Q Q Q Q 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 Negotiated and realized a lower insurance rate Continued Focus on Sustainable Cost Reduction and Optimization Savings in Multiple Categories While Maintaining Safety of Operations 22

23 Pipeline Facility Fee Gathering & Transportation $MM $25.0 $20.0 $15.0 $10.0 $21.7 $13.2 (1) $8.1 (1) $20.7 Guidance Midpoint $19.0 Pipeline Facility Fee flat $10.5 MM quarterly Gathering and Transportation past fluctuations due to: ONRR refunds in Q ~$5 MM and Q ~$11 MM $5.0 ONRR Lookback process continues $- No additional material ONRR refunds forecasted $(5.0) Q Q Q Q Q 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 1) Includes Gathering and Transportation credits related to ONRR refunds for the following quarters: Q217 ~$5MM, Q317 ~$11MM 23

24 G&A Expenses $30.0 Q costs 31% below Q $25.0 $20.0 $0.9 $2.9 Guidance Midpoint EGC realized $8 MM of annualized G&A savings due to reduced staffing from Q1 to Q $MM $15.0 $10.0 $5.0 $20.7 $17.8 $3.0 $2.7 $2.7 $12.0 $12.0 $ included $7.9 MM related to severance costs in addition to restructuring, reorganization and bankruptcy emergence charges $- Q Q Q Q Q1 2018E Cash G&A Non-Cash G&A Adjusting Staff Levels and Costs to Better Align with Operational Plan 24

25 2018 Operational Cash Flow Midpoint of 2018 production guidance: 28,000 BOEPD $/BOE $70.00 $60.00 $50.00 $40.00 $30.00 $18.08 $2.19 $10.13 $4.89 $4.89 $4.89 $7.19 $7.19 $7.19 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 $20.00 $30.52 $30.52 $30.52 $10.00 $- $50 $60 $70 Unhedged WTI Oil Price Total LOE (1) Total G&T (2) G&A (3) Operating Cash Margin (4,5) 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 Each $1/BBL Improvement in Oil Price Should Increase Annual Cash Flow $7-$9 MM (1) Includes direct LOE, WO/Maintenance, Insurance & Prod Taxes (2) Includes gathering & transportation and pipeline facility fee 3) Excludes non-cash compensation 5) Excludes Interest and Capex expenses 4) Includes forecasted $2.50/BBL of HLS/LLS differential premium 25

26 2019 Scenario with Enhanced Drilling This is not forward guidance, but a scenario based on the assumptions listed below $70.00 $60.00 $23.42 Enhanced drilling scenario 2019 production forecast: 32,000 BOEPD $/BOE $50.00 $40.00 $30.00 $15.48 $7.53 $4.28 $4.28 $4.28 $6.29 $6.29 $6.29 Forecasted 2019 absolute cost flat vs for Total LOE, Total G&T and G&A No hedges currently in place for 2019 $20.00 $10.00 $- $26.69 $26.69 $26.69 $50 $60 $70 Unhedged WTI Oil Price (1) (2) (3) Total LOE Total G&T G&A Operating Cash Margin (4,5) Enhanced drilling includes several high impact exploitation wells driving production increases 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 Optimized 2019 Scenario Would Yield Substantial Improvement in Results Assuming Additional Capital Available to Fund Program (1) Includes direct LOE, WO/Maintenance, Insurance & Prod Taxes (2) Includes gathering & transportation and pipeline facility fee 3) Excludes non-cash compensation 5) Excludes Interest and Capex expenses 4) Includes forecasted $2.50/BOE of HLS/LLS differential premium 26

27 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 Q 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. 27

28 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 Current Hedge Profile 2018 WTI Swaps LLS Swaps Brent Swaps BOPD 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Jan 18 Feb 18 Mar 18 Apr 18 May 18 Jun 18 Jul 18 Aug 18 Sep 18 Oct 18 Nov 18 Dec 18 Strategy: Hedge Opportunistically to Support the Base Business 28

29 Full Year 2018 Guidance (As of 03/16/18) Q Full Year 2018 Production (1) 26,000-27,000 BOEPD (2) 26,000-30,000 BOEPD (3) Direct LOE $60 - $70 MM $235 - $255 MM Workover/Maintenance $10 - $13 MM $40 - $50 MM Insurance Gathering & Transportation Pipeline Facility Fee $4 - $6 MM $7 - $10 MM $10 - $11 MM $18 - $23 MM $28 - $35 MM $41 - $43 MM General & Administrative $14 - $16 MM $55 - $65 MM DD&A $30 - $35 MM $120 - $130 MM Accretion of ARO $9 - $11 MM $36 - $44 MM Capital Expenditures (4) $35 - $45 MM $145 - $175 MM (1) Production is priced 60-70% HLS; 30-40% LLS (3) Forecast exit rate: 28,000 30,000 BOEPD (2) Reflects impact of curtailments due to weather & other (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 29

30 Factors Impacting EGC s Future Well Positioned for Future GOM Consolidation Highly Leveraged to Increasing Oil Prices Underutilized Infrastructure Enhances Opportunity with Low Incremental Costs Large Legacy Fields with Upside Potential Premium Realizations vs. WTI Strong and Clean Balance Sheet Fiscally Driven Board with Significant Expertise in Oil and Gas Execute Stand Alone Plan & Pursue Acquisitions Further Develop a High Performing Management and Technical Team Outlook For EGC In 2018 And Beyond Is Rapidly Improving 30

31 Appendix 31

32 Leadership Team 34 years experience 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 37 years experience 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 25 years experience 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 27 years experience 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 Strong, Proficient Executive Leadership With A Seasoned Board 32

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

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