8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8‑K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): November 14, 2017

Energy XXI Gulf Coast, Inc.

(Exact name of registrant as specified in its charter)

Delaware	001‑38019	20‑4278595
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

1021 Main, Suite 2626

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (713) 351‑3000

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8‑K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

◻Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

◻Soliciting material pursuant to Rule 14a‑12 under the Exchange Act (17 CFR 240.14a‑12)

◻Pre-commencement communications pursuant to Rule 14d‑2(b) under the Exchange Act (17 CFR 240.14d‑2(b))

◻Pre-commencement communications pursuant to Rule 13e‑4(c) under the Exchange Act (17 CFR 240.13e‑4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b‑2 of the Securities Exchange Act of 1934 (§240.12b‑2 of this chapter).

Emerging growth company ◻

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ◻

Item 2.02    Results of Operations and Financial Condition

On November 14, 2017, Energy XXI Gulf Coast, Inc. (the “Company”) issued a press release disclosing operational and financial results for the third quarter of 2017.  A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8‑K (this “Form 8‑K”).

Item 7.01    Regulation FD Disclosure

See “Item 2.02 Results of Operations and Financial Condition” above.

Effective as of November 14, 2017, the Company posted an investor presentation to its website in the Events and Presentations section of the Investor Relations tab at http://ir.energyxxi.com/earnings_call.cfm.  The Company undertakes no obligation to update this information, including any forward-looking statements, to reflect subsequently occurring events or circumstances.  A copy of the investor presentation is attached as Exhibit 99.2 to this Form 8‑K.

The information in this Form 8‑K, including Exhibits 99.1 and 99.2 attached hereto, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that Section, nor shall it be deemed subject to the requirements of amended Item 10 of Regulation S-K, nor shall it be deemed incorporated by reference into any filing of the Company under the Securities Act of 1933, as amended, or the Exchange Act, whether made before or after the date hereof, regardless of any general incorporation language in such filing.  The furnishing of this information hereby shall not be deemed an admission as to the materiality of any such information.

Item 9.01    Financial Statements and Exhibits

Exhibit Number	Description
99.1	Press Release issued by Energy XXI Gulf Coast, Inc. dated November 14, 2017
99.2	Investor presentation dated November 14, 2017

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EXHIBIT INDEX

Exhibit Number	Description
99.1	Press Release issued by Energy XXI Gulf Coast, Inc. dated November 14, 2017
99.2	Investor presentation dated November 14, 2017

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	ENERGY XXI GULF COAST, INC.
Date: November 14, 2017	By:	/s/ Douglas E. Brooks
		Douglas E. Brooks
		Chief Executive Officer and President

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EX-99.1

Exhibit 99.1

ENERGY XXI  GULF  COAST ANNOUNCES THIRD QUARTER 2017

FINANCIAL AND  OPERATIONAL RESULTS

HOUSTON – November 14, 2017 – Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) (NASDAQ: EXXI) today reported financial and operational results for the third quarter of 2017.

Third Quarter 2017 Highlights and Recent Key Items:

· Produced an average of approximately 32,600 barrels of oil equivalent (“BOE”) per day, of which 77% was oil; tropical weather reduced production an average of approximately 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

· Reduced total lease operating expense (“LOE”) by 9% quarter-over-quarter

· Lowered general and administrative costs (“G&A”) by 27% quarter-over-quarter

· Incurred a net loss of $31.6 million which included a loss on financial derivatives of $12.5 million ($14.4 million unrealized loss offset by $1.9 million realized gain)

· Generated Adjusted EBITDA of $35.3 million, up 45% from $24.4 million in the prior 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

· Reported cash and cash equivalents of $173 million at September 30, 2017 compared to $165 million at December 31, 2016

· Expanded 2018 commodity hedging program

· Provided summary of strategic alternatives review process

For the third quarter of 2017, EGC reported a  net loss of  $31.6 million or $0.95 loss per diluted share.  Despite reductions in total costs and expenses of $18.8 million, compared to the second quarter, third quarter 2017 financial results were negatively impacted by lower production and a loss on

derivative financial instruments. In the second quarter of 2017, the Company reported a net loss of $23.6 million, or $0.71 loss per diluted share.

Adjusted EBITDA totaled $35.3 million for the third quarter 2017, up 45% from $24.4 million in the second quarter of 2017.

Adjusted EBITDA is a Non-GAAP financial measure and is described and reconciled to net loss in the attached table under “Reconciliation of Non-GAAP Measures.”

Douglas E. Brooks, EGC’s Chief Executive Officer and President commented, “Our successful efforts to reduce LOE and G&A costs contributed to a 45%  improvement in Adjusted EBITDA quarter-over-quarter. We also further enhanced our hedge position for 2018 at an average oil price of around $52.00, and successfully completed and brought online our first new well in nearly two years. The West Delta 30 High Tide well, which we operate with a 100% working interest, came in about $1 million under the authorized expenditure for the well and is currently producing 650 BOE per day. We remain confident in our inventory of approximately 50 potential well locations that are available to us in the future.”

Brooks continued, “We have been working with our financial advisor on our long-term strategic plan for the past six months that focused initially on Gulf of Mexico consolidation discussions, where we felt that significant potential synergies could drive improved results for those involved.  We concurrently were developing a stand-alone strategy if that were determined to be the best option.  Since no executable combination has resulted from these discussions, we are now focused on our stand-alone options, which include a drilling program beginning in early 2018.  This activity in 2018 and beyond may be funded internally through existing liquidity, the benefit of higher oil prices, and continued progress on reducing costs, but could also require accessing the capital markets.  We will be finalizing our plan for 2018 over the next several weeks and expect to provide additional guidance early next year, but in the interim we have released a range of forward-looking scenarios that our Board has considered.  In all cases we will maintain our strong financial discipline and focus on operating safely, efficiently and effectively.  We will continue to drive down costs, enhance production with a recompletion and workover program, and evaluate potential dispositions of non-core properties.  We believe that these activities, coupled with an efficient capital investment program, will maximize value for our shareholders and maintain our optionality to include once again considering other strategic options should the opportunity arise in the future.”

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The Company posted an updated investor presentation on its web site this morning that includes additional detail on the results of the strategic review process,  full production and cost guidance for the fourth quarter of 2017, and a 2018 outlook along with varying scenarios related to its stand-alone forward strategy.  This presentation will be referenced in today’s conference call.

Revenue, Production and Pricing

Total revenues for the third quarter of 2017 were  $117.0 million, which includes a $12.5 million loss on derivative financial instruments, while in the second quarter, revenues totaled $143.7 million, which included a $9.4 million gain on derivatives.

In the third quarter, the Company produced and sold approximately 32,600 net BOE per day, which was comprised of 25,100 barrels of oil per day (“BOPD”) at an average realized price of $49.77 per barrel (“BBL”) (before the effect of derivatives),  800 barrels of natural gas liquids (“NGLs”)  per day at an average realized price of $32.15 per BBL, and 40.6 million cubic feet of gas (“MMCF”) per day at an average realized price of $3.28 per thousand cubic feet (“MCF”).  EGC’s realized oil price (before the effect of derivatives) was about 3% higher than average WTI prices during the quarter due to the positive differentials that EGC receives on it oil sales.  Tropical weather reduced production for the third quarter an average of approximately 1,200 BOE per day

In the second quarter, EGC produced and sold approximately 36,000 net BOE per day which was comprised of 26,800 BOPD at an average realized price of $48.45 per BBL (before the effect of derivatives), 1,000 barrels of NGLs per day at an average realized price of $27.37 per BBL, and 48.9 MMCF per day at an average realized price of $3.09 per MCF.  When compared with the second quarter, third quarter production declined primarily due to disruptions associated with shut-ins from tropical weather, production equipment maintenance, pipeline shut-ins,  facility-related unscheduled downtime and natural declines.

Third Quarter 2017 Costs and Expenses

Total LOE was  $77.8 million, or $25.93 per BOE, which consisted of  $64.3 million in direct lease operating expense,  $8.5 million in workover and maintenance and $5.0 million in insurance expense.  Total LOE for the second quarter of 2017 was $85.3 million, or $26.11 per BOE.  Lease operating expense was reduced 9% quarter-over-quarter primarily due to continued implementation of cost saving measures and reduced insurance premiums.

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Gathering and Transportation expense for the third quarter of 2017 was a credit of $2.4 million, or ($0.81) per BOE which included a net refund of $10.6 million from the Office of Natural Resources Revenue (“ONRR”) as part of a multi-year federal royalty refund claim, pipeline Facility Fee expense, which was previously included in Gathering and Transportation expense, was $10.5 million or $3.50 per BOE.  In the second quarter of 2017, Gathering and Transportation expense was $2.7 million, or $0.82 per BOE which included a $4.7 million ONRR refund, while Pipeline and Facility Fee expense was $10.5 million or $3.21 per BOE.

G&A expense in the third quarter of 2017 was $15.0 million, or $5.01 per BOE compared to $20.7 million, or $6.34 per BOE in the second quarter 2017.   G&A expense was reduced 27% quarter-over-quarter due to continued efforts to bring organizational costs in line with operational needs. G&A includes non-cash compensation costs of $3.0 million ($1.00 per BOE) in the third quarter compared with $2.9 million ($0.88 per BOE) in the second quarter.

Depreciation, depletion and amortization (“DD&A”) expense was $36.1 million, or $12.01 per BOE compared to $38.7 million, or $11.83 per BOE in the second quarter of 2017.

Accretion of asset retirement obligation was $9.9 million during the third quarter 2017 differing slightly from $10.1 million in the second quarter.

For the first nine months of 2017, EGC recorded no income tax expense or benefit.

Commodity Hedging

During the third quarter, EGC entered into fixed price swap contracts benchmarked to NYMEX-WTI, to hedge a total of 8,000 BOPD of production for full year 2018 with an average fixed price swap of $50.68 and fixed price swap contracts benchmarked to LLS-Argus for 2,000 BOPD with an average fixed price of $55.45 for the period of January – June 2018.  In October, the Company entered into 2,500 BOPD fixed price swap contracts benchmarked to ICE-Brent for January to June 2018 with an average fixed price of $56.59.  For the remainder of calendar 2017, EGC has fixed price swap contracts benchmarked to NYMEX-WTI for 1,500 BOPD of production at an average fixed price swap of $51.68, 3,500 BOPD of production for November 2017 and December 2017 with an average fixed price swap of $51.81, in addition to costless collars covering 10,000 BOPD, with an average floor price of $52.30 and an average ceiling price of $57.43 per barrel.  The Company

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continues to evaluate additional derivative arrangements to help limit the downside risk of adverse price movements.  EGC does not have any hedges in place on natural gas production.

Operational Update and Capital Expenditure Program

The High Tide well at West Delta 30 that was successfully drilled by the Company with a 100% working interest had first production on September 9, 2017 and is currently producing 650 BOE per day. The cost of the well came in 10% below Authorization for Expenditure (“AFE”) costs. The total drilling and completion costs, net of hurricane costs, were $9.0 million versus an AFE cost of $10.1 million.

During the quarter the Company had to evacuate personnel and shut-in production several times due to multiple storms in the Gulf of Mexico.  While EGC was impacted by curtailed production during the quarter, there was no material damage to any of the Company’s platforms or facilities.

During the three months ended September 30, 2017, the Company incurred capital costs, including abandonment activities, totaling $36.5 million.  

Balance Sheet and Liquidity

At September 30, 2017, EGC had approximately $74 million in borrowings and $202.8 million in letters of credit issued under its exit credit agreement. Liquidity totaled approximately $186 million which is comprised of cash and cash equivalents totaling $173 million and $12.5 million in borrowing capacity available under certain conditions.

Conference Call

As previously announced, the Company will hold a conference call to discuss its third quarter financial and operating results today,  Tuesday,  November 14, 2017, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time). Interested parties may participate by dialing (877)  794‑3620.  International parties may dial (631)  813‑4724.  The confirmation code is 7678989.  This call will also be webcast on EGC’s website at www.energyxxi.com. A replay of the call will be archived and available on the web site shortly after the live call.

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Fresh Start Accounting

Upon emergence from the Company’s  Chapter 11 restructuring, EGC elected to adopt fresh start accounting as of December 30, 2016. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after December 31, 2016 are not comparable with the financial statements prior to that date. References to “Successor” refer to the reorganized EGC subsequent to the adoption of fresh start accounting. References to “Predecessor” refer to Energy XXI Ltd. prior to the adoption of fresh start accounting.

Non-GAAP Measures

Adjusted EBITDA is a supplemental non-GAAP financial measure.  Adjusted EBITDA is not a measure of net income or cash flows as determined by United States Generally Accepted Accounting Principles, (“U.S. 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 from the calculation of Adjusted EBITDA. 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 U.S. 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.

Cautionary Note Regarding Forward-Looking Statements

This press release 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

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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.

About the Company

Energy XXI Gulf Coast, Inc. is an independent oil and natural gas development and production company whose assets are primarily located in the U.S. Gulf of Mexico waters offshore Louisiana and Texas.  The Company’s near-term strategy emphasizes exploitation of key assets, enhanced by its focus on financial discipline and operational excellence.  To learn more, visit EGC’s website at www.energyxxi.com.

Investor Relations Contact

Al Petrie

Investor Relations Coordinator

713‑351‑3171

apetrie@energyxxi.com

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	Successor
	September 30,		June 30,		December 31,
	2017		2017		2016
	(Unaudited)		(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	173,364	$	178,855	$	165,368
Accounts receivable
Oil and natural gas sales		49,200		52,691		68,143
Joint interest billings, net		3,249		2,498		5,600
Other		17,762		8,318		17,944
Prepaid expenses and other current assets		16,096		17,176		25,957
Restricted cash		6,378		6,365		32,337
Derivative financial instruments		—		10,470		—
Total Current Assets		266,049		276,373		315,349
Property and Equipment
Oil and natural gas properties, net - full cost method of accounting, including $219.1 million, $224.5 million and $376.1 million of unevaluated properties not being amortized at September 30, 2017, June 30, 2017 and December 31, 2016, respectively		869,810		869,398		1,097,479
Other property and equipment, net		13,860		15,107		18,807
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		883,670		884,505		1,116,286
Other Assets
Restricted cash		25,675		25,637		25,583
Other assets		26,840		27,011		28,244
Total Other Assets		52,515		52,648		53,827
Total Assets	$	1,202,234	$	1,213,526	$	1,485,462
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	86,691	$	80,891	$	101,117
Accrued liabilities		38,652		34,517		63,660
Asset retirement obligations		64,066		61,766		56,601
Derivative financial instruments		3,302		—		—
Current maturities of long-term debt		23		3,443		4,268
Total Current Liabilities		192,734		180,617		225,646
Long-term debt, less current maturities		73,946		73,940		74,229
Asset retirement obligations		556,301		553,515		696,763
Derivative financial instruments		574		—		—
Other liabilities		18,134		16,347		14,481
Total Liabilities		841,689		824,419		1,011,119
Commitments and Contingencies
Stockholders’ Equity
Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at September 30, 2017, June 30, 2017 and December 31, 2016		—		—		—
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,221,427, 33,221,427 and 33,211,594 shares issued and outstanding at September 30, 2017, June 30, 2017 and December 31, 2016 respectively		332		332		332
Additional paid-in capital		887,026		884,008		880,286
Accumulated deficit		(526,813)		(495,233)		(406,275)
Total Stockholders’ Equity		360,545		389,107		474,343
Total Liabilities and Stockholders’ Equity	$	1,202,234	$	1,213,526	$	1,485,462

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, except per share information)

(Unaudited)

	Successor				Predecessor
	Three Months Ended		Three Months Ended		Three Months Ended
	September 30,		June 30,		September 30,
	2017		2017		2016
Revenues
Oil sales	$	114,991	$	118,180	$	122,732
Natural gas liquids sales		2,209		2,370		2,144
Natural gas sales		12,261		13,753		17,735
(Loss) gain on derivative financial instruments		(12,466)		9,412		—
Total Revenues		116,995		143,715		142,611
Costs and Expenses
Lease operating		77,822		85,336		65,170
Production taxes		471		482		214
Gathering and transportation		(2,441)		2,678		7,534
Pipeline facility fee		10,495		10,494		10,165
Depreciation, depletion and amortization		36,066		38,661		31,573
Accretion of asset retirement obligations		9,892		10,050		19,437
Impairment of oil and natural gas properties		(2,357)		(848)		86,820
General and administrative expense		15,026		20,716		15,435
Reorganization items		—		(3,773)		—
Total Costs and Expenses		144,974		163,796		236,348
Operating Loss		(27,979)		(20,081)		(93,737)
Other (Expense) Income
Other income, net		52		80		62
Interest expense		(3,653)		(3,642)		(4,838)
Total Other Expense , net		(3,601)		(3,562)		(4,776)
Loss Before Reorganization Items and Income Taxes		(31,580)		(23,643)		(98,513)
Reorganization items		—		—		(32,633)
Loss Before Income Taxes		(31,580)		(23,643)		(131,146)
Income Tax Benefit		—		—		—
Net Loss		(31,580		(23,643)		(131,146)
Preferred Stock Dividends		—		—		—
Net Loss Attributable to Common Stockholders	$	(31,580)	$	(23,643)	$	(131,146)
Loss per Share
Basic and Diluted	$	(0.95)	$	(0.71)	$	(1.34)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted		33,241		33,237		97,824

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Successor				Predecessor
	Three Months Ended		Three Months Ended		Three Months Ended
	September 30,		June 30,		September 30,
	2017		2017		2016
Cash Flows From Operating Activities
Net loss	$	(31,580)	$	(23,643)	$	(131,146)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		36,066		38,661		31,573
Impairment of oil and natural gas properties		(2,357)		(848)		86,820
Change in fair value of derivative financial instruments		14,346		(7,061)		—
Accretion of asset retirement obligations		9,892		10,050		19,437
Amortization and write off of debt issuance costs and other		5		6		876
Deferred rent		1,930		2,016		1,685
Provision for loss on accounts receivable		—		300		—
Reorganization items		(113)		(3,773)		—
Stock-based compensation		3,019		2,870		109
Changes in operating assets and liabilities
Accounts receivable		(6,704)		12,153		6,012
Prepaid expenses and other assets		669		4,165		534
Restricted cash		(51)		718		—
Settlement of asset retirement obligations		(12,293)		(18,175)		(16,953)
Accounts payable, accrued liabilities and other		3,583		8,515		21,204
Net Cash Provided by Operating Activities		16,412		25,954		20,151
Cash Flows from Investing Activities
Capital expenditures		(18,531)		(5,391)		(7,682)
Insurance payments received		—		(2,010)		—
Transfer to restricted cash		—		—		(48)
Proceeds from the sale of other property and equipment		47		10		—
Other		—		—		71
Net Cash Used in Investing Activities		(18,484)		(7,391)		(7,659)
Cash Flows from Financing Activities
Payments on long-term debt		(3,419)		(126)		—
Debt issuance costs		—		(61)		(37)
Net Cash Used in Financing Activities		(3,419)		(187)		(37)
Net Increase (Decrease) in Cash and Cash Equivalents		(5,491)		18,376		12,455
Cash and Cash Equivalents, beginning of period		178,855		160,479		203,258
Cash and Cash Equivalents, end of period	$	173,364	$	178,855	$	215,713

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ENERGY XXI GULF COAST, INC.

RECONCILIATION OF NON-GAAP MEASURES

(In Thousands, except per share information)

(Unaudited)

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 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

⁽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

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Operational Information

	Successor				Predecessor
	Quarter Ended				Quarter Ended
	September 30,		June 30,		September 30,
Operating Highlights	2017		2017		2016
	(In thousands, except per unit amounts)
Operating revenues
Oil sales	$	114,991	$	118,180	$	122,732
Natural gas liquids sales		2,209		2,370		2,144
Natural gas sales		12,261		13,753		17,735
(Loss) gain on derivative financial instruments		(12,466)		9,412		—
Total revenues		116,995		143,715		142,611
Percentage of oil revenues prior to (loss) gain on derivative financial instruments		89%		88%		86%
Operating expenses
Lease operating expense
Insurance expense		5,040		7,101		6,309
Workover and maintenance		8,490		13,370		11,010
Direct lease operating expense		64,292		64,865		47,851
Total lease operating expense		77,822		85,336		65,170
Production taxes		471		482		214
Gathering and transportation		(2,441)		2,678		7,534
Pipeline facility fee		10,495		10,494		10,165
Depreciation, depletion and amortization		36,066		38,661		31,573
Accretion of asset retirement obligations		9,892		10,050		19,437
Impairment of oil and natural gas properties		(2,357)		(848)		86,820
General and administrative		15,026		20,716		15,435
Reorganization items		—		(3,773)		—
Total operating expenses		144,974		163,796		236,348
Operating loss	$	(27,979)	$	(20,081)	$	(93,737)
Sales volumes per day
Oil (MBbls)		25.1		26.8		30.0
Natural gas liquids (MBbls)		0.8		1.0		1.3
Natural gas (MMcf)		40.6		48.9		72.8
Total (MBOE)		32.6		35.9		43.4
Percent of sales volumes from oil		77%		75%		69%
Average sales price
Oil per Bbl	$	49.77	$	48.45	$	44.52
Natural gas liquid per Bbl		32.15		27.37		18.12
Natural gas per Mcf		3.28		3.09		2.65
(Loss) gain on derivative financial instruments per BOE		(4.15)		2.88		—
Total revenues per BOE		38.97		43.99		35.73
Operating expenses per BOE
Lease operating expense
Insurance expense		1.68		2.17		1.58
Workover and maintenance		2.83		4.09		2.76
Direct lease operating expense		21.42		19.85		11.99
Total lease operating expense per BOE		25.93		26.11		16.33
Production taxes		0.16		0.15		0.05
Gathering and transportation		(0.81)		0.82		1.89
Pipeline facility fee		3.5		3.21		2.55
Depreciation, depletion and amortization		12.01		11.83		7.91
Accretion of asset retirement obligations		3.3		3.08		4.87
Impairment of oil and natural gas properties		(0.79)		(0.26)		21.75
General and administrative		5.01		6.34		3.87
Reorganization items		—		(1.15)		—
Total operating expenses per BOE		48.31		50.13		59.22
Operating loss per BOE	$	(9.34)	$	(6.14)	$	(23.49)

12

EX-99.2

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