UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2017

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to          

Commission File Number: 001-38019

 

ENERGY XXI GULF COAST, INC.

(Exact name of registrant as specified in its charter)

 

Delaware		20-4278595
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1021 Main, Suite 2626 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 351-3000

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer” “accelerated filer” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o
Non-accelerated filer þ		Smaller reporting company o
(Do not check if a smaller reporting company)		Emerging growth company o

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) if the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes þ No o

As of August 7, 2017, there were 33,221,427 shares outstanding of the registrant’s common stock, par value $0.01 per share.

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ENERGY XXI GULF COAST, INC.
 
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		Page
GLOSSARY OF TERMS			1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			4
PART I — FINANCIAL INFORMATION
ITEM 1. Unaudited Consolidated Financial Statements			6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			45
ITEM 4. Controls and Procedures			46
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings			47
ITEM 1A. Risk Factors			47
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds			47
ITEM 3. Defaults upon Senior Securities			47
ITEM 4. Mine Safety Disclosures			47
ITEM 5. Other Information			47
ITEM 6. Exhibits			47
SIGNATURES			48
EXHIBIT INDEX			49

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GLOSSARY OF TERMS

Bankruptcy Terms

On April 14, 2016 (the “Petition Date”), Energy XXI Ltd (“EXXI Ltd”), an exempt company incorporated under the laws of Bermuda and predecessor of Reorganized EGC (as defined below), Energy XXI Gulf Coast, Inc., then an indirect wholly-owned subsidiary of EXXI Ltd (“EGC”), EPL Oil & Gas Inc., then an indirect wholly-owned subsidiary of EXXI Ltd (“EPL”) and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the United States Bankruptcy Court for the Southern District of Texas, Houston Division seeking relief under the provisions of chapter 11 of Title 11 of the United States Code.

In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC (the “Reorganized EGC”). On December 30, 2016 (the “Emergence Date”), the entities emerged from bankruptcy and shares of common stock and common stock warrants of Reorganized EGC were distributed to creditors of the Debtors (defined below) pursuant to the Plan (defined below). In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), the Reorganized EGC was required to apply fresh start accounting upon EXXI Ltd’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

As used throughout this quarterly report on Form 10-Q for the quarter ended June 30, 2017 (this “Quarterly Report”), references to “Reorganized EGC”, the “Company,” “we,” “our”, “Successor”, “Successor Company” or similar terms when used in reference to the period subsequent to the emergence from the bankruptcy refer to Reorganized EGC, the new parent entity and successor issuer of EXXI Ltd pursuant to Rule 12g-3(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). References in this Quarterly Report to “EXXI Ltd,” “we,” “our”, “Predecessor”, “Predecessor Company” or similar terms when used in reference to the periods prior to the emergence from the bankruptcy refer to EXXI Ltd, the predecessor and former parent entity that was dissolved upon the completion of the Bermuda Proceeding (as defined below). References in this Quarterly Report to “EGC” refer to EGC in the periods prior to the emergence from the bankruptcy during which it was the indirect wholly-owned operating subsidiary of EXXI Ltd.

Below is a list of additional terms relating to the bankruptcy as used throughout this Quarterly Report:

Bankruptcy Code means title 11 of the United States Code, as amended and in effect during the pendency of the Chapter 11 Cases.

Bankruptcy Court means the United States Bankruptcy Court for the Southern District of Texas, Houston Division.

Bankruptcy Petitions means the Debtors’ voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11 under the caption In re Energy XXI Ltd, et al., Case No. 16-31928.

Bermuda Proceeding means the official liquidation proceeding for EXXI Ltd under the laws of Bermuda commenced pursuant to the winding-up petition before the Bermuda Court and completed as of June 29, 2017.

Bermuda Court means the Supreme Court of Bermuda, Commercial court.

Chapter 11 means chapter 11 of the Bankruptcy Code.

Chapter 11 Cases means the Debtors’ procedurally consolidated and jointly administered Chapter 11 cases in the Bankruptcy Court.

Confirmation Order means the order dated December 13, 2016 entered by the Bankruptcy Court approving and confirming the Plan pursuant to section 1129 of the Bankruptcy Code.

Debtors means, collectively, the following: Anglo-Suisse Offshore Pipeline Partners, LLC, Delaware EPL of Texas, LLC, Energy Partners Ltd., LLC, Energy XXI GOM, LLC, EGC, Energy XXI Holdings, Inc.,

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Energy XXI, Inc., Energy XXI Leasehold, LLC, EXXI Ltd, Energy XXI Natural Gas Holdings, Inc., Energy XXI Offshore Services, Inc., Energy XXI Onshore, LLC, Energy XXI Pipeline, LLC, Energy XXI Pipeline II, LLC, Energy XXI Services, LLC, Energy XXI Texas Onshore, LLC, Energy XXI USA, Inc., EPL of Louisiana, L.L.C., EPL, EPL Pioneer Houston, Inc., EPL Pipeline, L.L.C., M21K, LLC, MS Onshore, LLC, Natural Gas Acquisition Company I, LLC, Nighthawk, L.L.C., and Soileau Catering, LLC.

Emergence Date means December 30, 2016.

Convenience Date means December 31, 2016.

Petition Date means April 14, 2016.

Plan means the Debtors’ Second Amended Proposed Joint Chapter 11 Plan of Reorganization (as amended, modified, or supplemented from time to time).

Reorganized Debtors means the Debtors after completing the series of internal reorganization transactions in accordance with the Plan, pursuant to which, among other things, EXXI Ltd transferred all of its remaining assets to Reorganized EGC.

Industry Terms

In addition, below is a list of terms that are common to our industry and where applicable used throughout this Quarterly Report:

Bbls		Standard barrel containing 42 U.S. gallons		MMBbls		One million Bbls
Mcf		One thousand cubic feet		MMcf		One million cubic feet
Btu		One British thermal unit		MMBtu		One million Btu
BOE		Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil		MBOE		One thousand BOEs
DD&A		Depreciation, Depletion and Amortization		MMBOE		One million BOEs
Bcf		One billion cubic feet		NGLs		Natural gas liquids
BPD		Barrels per day

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and/or crude oil from a recently drilled or recompleted well.

Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well or a service well.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a)(8) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

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Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the fractional working interest owned in the properties.

Oil includes crude oil, condensate and NGLs.

Costs and expenses include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain wells and related equipment and facilities.

Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a)(20) of Regulation S-X as promulgated by the SEC.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. For a complete definition of proved reserves, refer to Rule 4-10(a)(22) of Regulation S-X as promulgated by the SEC.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a)(6) of Regulation S-X as promulgated by the SEC.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4-10(a)(314) of Regulation S-X as promulgated by the SEC.

Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover refers to the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.

Zone is a stratigraphic interval containing one or more reservoirs.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances and their potential effect on us. While management believes that these forward-looking statements are reasonable, such statements are not guarantees of future performance and the actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:

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For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read (1) Part I, “Item 1A. Risk Factors” in our transition report on Form 10-K for the six month transition period ended December 31, 2016 (the “2016 Transition Report”) (2) Part II, “Item 1A. Risk Factors” in this Quarterly Report (3) our reports and registration statements filed from time to time with the SEC and (4) other public announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date upon which they are made, whether as a result of new information, future events or otherwise.

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PART I — FINANCIAL INFORMATION

ITEM 1. Unaudited Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)

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

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)
(Unaudited)

		Successor				Predecessor				Successor				Predecessor
		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016				Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Revenues
Oil sales		$	118,180			$	130,083			$	251,801			$	222,275
Natural gas liquids sales			2,370				2,996				4,597				5,885
Natural gas sales			13,753				14,725				32,121				29,155
Gain on derivative financial instruments			9,412				—				13,110				6,774
Total Revenues			143,715				147,804				301,629				264,089
Costs and Expenses
Lease operating			85,336				76,803				160,493				154,423
Production taxes			482				155				721				376
Gathering and transportation			13,172				14,260				34,888				32,839
Depreciation, depletion and amortization			38,661				40,078				80,667				93,925
Accretion of asset retirement obligations			10,050				18,905				22,447				33,962
Impairment of oil and natural gas properties			(848	)			142,640				43,206				483,109
General and administrative expense			20,716				23,174				42,320				51,532
Reorganization items			(3,773	)			—				(1,529	)			—
Total Costs and Expenses			163,796				316,015				383,213				850,166
Operating Loss			(20,081	)			(168,211	)			(81,584	)			(586,077	)
Other (Expense) Income
Other income, net			80				160				102				548
Gain on early extinguishment of debt			—				—				—				777,022
Interest expense			(3,642	)			(13,438	)			(7,476	)			(212,206	)
Total Other (Expense) Income, net			(3,562	)			(13,278	)			(7,374	)			565,364
Loss Before Reorganization Items and Income Taxes			(23,643	)			(181,489	)			(88,958	)			(20,713	)
Reorganization items			—				(14,201	)			—				(14,201	)
Loss Before Income Taxes			(23,643	)			(195,690	)			(88,958	)			(34,914	)
Income Tax Benefit			—				(138	)			—				(138	)
Net Loss			(23,643	)			(195,552	)			(88,958	)			(34,776	)
Preferred Stock Dividends			—				352				—				2,730
Net Loss Attributable to Common Stockholders		$	(23,643	)		$	(195,904	)		$	(88,958	)		$	(37,506	)
Loss per Share
Basic and Diluted		$	(0.71	)		$	(2.01	)		$	(2.68	)		$	(0.39	)
Weighted Average Number of Common Shares Outstanding
Basic and Diluted			33,237				97,540				33,234				96,728

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI GULF COAST, INC.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)

		Successor				Predecessor
		Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Cash Flows From Operating Activities
Net loss		$	(88,958	)		$	(34,776	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			80,667				93,925
Impairment of oil and natural gas properties			43,206				483,109
Gain on early extinguishment of debt			—				(777,022	)
Change in fair value of derivative financial instruments			(10,470	)			61,325
Accretion of asset retirement obligations			22,447				33,962
Amortization and write off of debt issuance costs and other			6				127,356
Deferred rent			4,031				4,577
Provision for loss on accounts receivable			300				3,200
Reorganization items			(3,773	)			—
Stock-based compensation			3,722				349
Changes in operating assets and liabilities
Accounts receivable			27,880				(28,131	)
Prepaid expenses and other assets			11,134				(13,437	)
Restricted cash			25,919				—
Settlement of asset retirement obligations			(27,491	)			(24,554	)
Accounts payable, accrued liabilities and other			(51,168	)			(6,614	)
Net Cash Provided by (Used in) Operating Activities			37,452				(76,731	)
Cash Flows from Investing Activities
Capital expenditures			(24,496	)			(36,100	)
Insurance payments received			41				3,872
Transfer to restricted cash			—				(8,781	)
Proceeds from the sale of other property and equipment			1,279				1,070
Other			—				(102	)
Net Cash Used in Investing Activities			(23,176	)			(40,041	)
Cash Flows from Financing Activities
Proceeds from the issuance of common and preferred stock, net of offering costs			—				22
Payments on long-term debt			(728	)			(2,880	)
Fees related to debt extinguishment			—				(1,446	)
Debt issuance costs			(61	)			(1,531	)
Other			—				(25	)
Net Cash Used in Financing Activities			(789	)			(5,860	)
Net Increase (Decrease) in Cash and Cash Equivalents			13,487				(122,632	)
Cash and Cash Equivalents, beginning of period			165,368				325,890
Cash and Cash Equivalents, end of period		$	178,855			$	203,258

 
 
See accompanying Notes to Consolidated Financial Statements.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — Organization

Nature of Operations

Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation, was incorporated on February 7, 2006. Prior to emergence from the Chapter 11 Cases, EGC was an indirect wholly-owned operating subsidiary of Energy XXI Ltd (“EXXI Ltd”). We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf (“GoM Shelf”), which is an area in less than 1,000 feet of water.

Emergence from Chapter 11

On April 14, 2016, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of the Reorganized EGC (as defined below), EGC, EPL Oil & Gas Inc., then an indirect wholly-owned subsidiary of EXXI Ltd (“EPL”) and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order and on December 30, 2016, the Debtors emerged from bankruptcy.

On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Debtors emerged from Chapter 11 Cases. In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to EGC (the “Reorganized EGC”), as the new parent entity. Accordingly, Reorganized EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. In accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”), the Reorganized EGC applied fresh start accounting upon the Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

For reporting purposes, the pre-reorganization predecessor reflects the business that was transferred to the Reorganized EGC. The financial statements of the pre-reorganization predecessor are EXXI Ltd’s consolidated financial statements.

Our common stock began trading on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI” at the opening of business on February 28, 2017.

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements on June 30, 2017 include the accounts of Reorganized EGC and its wholly-owned subsidiaries and for the prior period, the accompanying consolidated financial statements include the accounts of EXXI Ltd and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The Predecessor’s consolidated financial statements for the prior period include certain reclassifications, including a $4.2 million and $8.6 million reclassification from lease operating expenses to gathering and transportation expenses for the three and six months ended June 30, 2016, respectively, to conform to the current presentation. Such reclassifications did not have any impact on the Predecessor’s previously reported consolidated result of operations or cash flows.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

For periods subsequent to filing the Bankruptcy Petitions, we have prepared the Predecessor’s consolidated financial statements in accordance with ASC 852. ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.

Correction of Immaterial Errors.  Our unaudited consolidated financial statements for the three and six months ended June 30, 2017 include certain adjustments that pertain to prior periods. For the three months ended June 30, 2017, lease operating expenses include $2.2 million of expenses and impairment of oil and natural gas properties includes $0.8 million in credit adjustments that pertained to first quarter 2017. Additionally, the three and six months ended June 30, 2017 include credit adjustments to reorganization items of $3.8 million to adjust the fresh start accounting opening balance sheet related to asset retirement obligations and other property, plant and equipment. The amounts are not deemed material with respect to the prior year, the first quarter of 2017 or the anticipated results for fiscal year 2017.

Fresh-start Accounting.  Upon emergence from bankruptcy, in accordance with ASC 852 related to fresh-start accounting, Reorganized EGC became a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Convenience Date. The effects of the Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in the consolidated statement of operations of the Predecessor as reorganization items in the 2016 Transition Report. Accordingly, Reorganized EGC’s consolidated financial statements as of and subsequent to December 31, 2016 are not and will not be comparable to the Predecessor consolidated financial statements prior to the Convenience Date. Our consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented for the three and six months ended June 30, 2017 and comparable prior periods. Although our accounting policies are the same as that of our Predecessor’s, our financial results for future periods following the application of fresh-start accounting will be different from historical trends, and the differences may be material.

Use of Estimates.  The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. The Predecessor’s proved reserves quantities of 86.6 MMBOE as of June 30, 2016 were estimated and compiled by its internal reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”). As of December 31, 2016, proved reserves quantities of 121.9 MMBOE were independently estimated and compiled by our internal reservoir engineers. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017. The first NSAI report was delivered by us on May 23, 2017. In it, NSAI estimated our proved reserves quantities of 109.4 MMBOE as of March 31, 2017 in accordance with the guidelines established by the SEC. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; reorganization items and liabilities subject to compromise, among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.

Interim Financial Statements.  The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2016 Transition Report.

Recent Accounting Pronouncements.  In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), as a new Accounting Standards Codification (ASC) Topic, ASC 606. ASU 2014-09 is effective for us beginning in the first quarter of 2018, with early adoption permitted from the first quarter of 2017. We have developed a project plan for the implementation of ASC 606 in the first quarter of 2018, and conducted an evaluation of a sample of revenue contracts with customers against the requirements of the standard. Further analysis is planned in 2017 to complete the implementation plan. Based on our assessment to date, we have not identified any changes to the timing of revenue recognition based on the requirements of ASC 606 that would have a material impact on our consolidated financial statements. We plan to adopt ASC 606 using the modified retrospective method that requires application of the new standard prospectively from the date of adoption with a cumulative effect adjustment, if any, recorded to retained earnings as of January 1, 2018.

In February 2016, the FASB issued ASU No. 2016-02, Leases (“ASU 2016-02”), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB Accounting Standards Codification and created Topic 842, Leases. The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In the normal course of business, we enter into capital and operating lease agreements to support our operations. We are in the initial stages of evaluating the provisions of ASU 2016-02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU could have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities.

In March 2016, the FASB issued ASU No. 2016-09 (“ASU 2016-09”), Compensation — Stock Compensation, to reduce complexity and enhance several aspects of accounting and disclosure for share-based payment transactions, including the accounting for income taxes, award forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016-09 was effective for annual and interim periods beginning after December 15, 2016, with earlier application permitted. Our adoption of ASU 2016-09 on January 1, 2017 had no effect on our consolidated financial position, results of operations or cash flows.

In June 2016, the FASB issued ASU No. 2016-13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”). ASU 2016-13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 2 — Summary of Significant Accounting Policies and Recent Accounting Pronouncements  – (continued)

ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The new guidance in ASU 2016-15 is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The new standard is effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted provided that all of the amendments are adopted in the same period. The guidance requires application using a retrospective transition method. We have not yet determined the effect of this standard on our consolidated cash flows.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016-18). ASU 2016-18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. This ASU will be effective for annual and interim periods beginning after December 15, 2017, with earlier application permitted. We do not expect the adoption of ASU 2016-18 will have a material impact on our statement of cash flows and related disclosures.

Note 3 — Property and Equipment

Property and equipment consists of the following (in thousands):

		Successor
		As of June 30, 2017				As of December 31, 2016
Oil and natural gas properties – full cost method of accounting Proved properties		$	1,169,543			$	1,127,616
Less: accumulated depreciation, depletion, amortization and impairment			(524,636	)			(406,275	)
Proved properties, net			644,907				721,341
Unevaluated properties			224,491				376,138
Oil and natural gas properties, net			869,398				1,097,479
Other property and equipment			18,046				18,807
Less: accumulated depreciation and impairment			(2,939	)			—
Other property and equipment, net			15,107				18,807
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	884,505			$	1,116,286

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net capitalized costs of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 3 — Property and Equipment  – (continued)

three months ended June 30, 2017, we reduced the impairment of our oil and natural gas properties by $0.8 million to reflect the correction of an immaterial error in certain asset retirement obligations included in the first quarter 2017 impairment calculation. For the three months ended March 31, 2017, our ceiling test computation resulted in impairment of our oil and natural gas properties of $44.1 million. For the six months ended June 30, 2017, we had a net impairment of our oil and natural gas properties of $43.2 million. We incurred an impairment primarily due to the difference in SEC proved reserves and the related PV-10 value (the net present value, determined using a discount rate of 10% per annum, of the future net revenues expected to accrue to the proved reserves of the Company and its subsidiaries) as of March 31, 2017 prepared by NSAI compared with SEC reserves and PV-10 value as of December 31, 2016 that were prepared by our internal reservoir engineers. The primary non-commodity price factors contributing to the difference between the NSAI March 31, 2017 SEC reserve report and the internally-prepared December 31, 2016 SEC reserve report are: (i) technical reassessments, (ii) higher capital costs and (iii) production during the first quarter of 2017. The impact of those factors was partially offset by higher SEC average commodity prices for both crude oil and natural gas. If oil and natural gas prices decline or our costs increase, we may incur further impairment to our full cost pool.

Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of (i) a determination as to whether there are any proved reserves related to the properties or the costs are impaired, (ii) a determination that the capital costs associated with the development of these properties will not be available, or (iii) ratably over a period of time of not more than four years or three years as it relates to unevaluated property costs recorded as part of fresh start accounting. For the six months ended June 30, 2017, the unevaluated properties costs decreased by $151.6 million, of which $103.4 million was transferred to evaluated properties due to the drop in near term pricing making certain unevaluated properties uneconomical and the remaining $48.2 million was the ratable amortization to the evaluated properties.

Note 4 — Long-Term Debt

As of June 30, 2017 and December 31, 2016 our outstanding debt consisted of the following (in thousands):

		Successor
		June 30, 2017				December 31, 2016
Exit Facility		$	73,996			$	73,996
4.14% Promissory Note due October 2017			3,415				4,001
Capital lease obligations			28				500
Total debt			77,439				78,497
Less: debt issue costs			56				—
Less: current maturities			3,443				4,268
Total long-term debt		$	73,940			$	74,229

Exit Facility

Pursuant to the Plan, on the Emergence Date, the Company, as Borrower, and the other Reorganized Debtors entered into a secured Exit Facility which matures on December 30, 2019. The Exit Facility is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors’ proved developed producing reserves as well as our total proved reserves. The Exit Facility is comprised of two facilities: (i) a term loan facility (the “Exit Term Loan”) resulting from the conversion of the remaining drawn amount plus accrued default interest, fees and expenses under the Debtors’ Second Amended and Restated First Lien Credit Agreement (the “Prepetition Revolving Credit Facility”) of approximately $74 million and (ii) a revolving credit facility (the “Exit Revolving Facility”) resulting from the conversion of the former EGC tranche of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4 — Long-Term Debt  – (continued)

Prepetition Revolving Credit Facility which provides, subject to the limitations noted below, for the making of revolving loans and the issuance of letters of credit.

Interest on the outstanding amount of the Exit Term Loan, at the Company’s option, will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly.

On the Emergence Date, the aggregate credit capacity under the Exit Revolving Facility was approximately $227.8 million, all of which was utilized to maintain in effect outstanding letters of credit, including $225 million of letters of credit issued in favor of ExxonMobil to secure certain plugging and abandonment obligations related to assets in the GoM. On April 26, 2016, pursuant to the redetermination of our plugging and abandonment liabilities with ExxonMobil, it was agreed that subsequent to the Predecessor Company’s emergence from the Chapter 11 proceedings, the letters of credit issued in favor ExxonMobil would be reduced to $200 million from the existing amount of $225 million and, on March 13, 2017, the letters of credit issued in favor ExxonMobil were reduced to $200 million. Each existing letter of credit may be renewed or replaced (in each case, in an outstanding amount not to exceed the outstanding amount of the existing letter of credit).

Following the reduction of $25 million in the letters of credit issued in favor ExxonMobil, the credit capacity under the Exit Revolving Facility was permanently reduced by 50% of the $25 million reduction in the letters of credit, or $12.5 million. The remaining 50%, or $12.5 million, of such aggregate reduction is available for borrowing, under specific circumstances, as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined at a date elected by the Company, and will be redetermined semi-annually thereafter. Currently, the Company has not elected a date for the initial borrowing base determination.

The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in the revolving credit capacity would cause the revolving credit exposure to exceed the revolving credit capacity. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises.

Furthermore, for each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan in an amount equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on the Emergence Date or (ii) the then outstanding principal amount of the Exit Term Loan. Based upon the Company’s current expectations with respect to its capital resources, capital expenditures, results from operations and commodity prices, the Company believes that it is reasonably likely that it will be required to make a mandatory prepayment with respect to each fiscal quarter beginning with the quarter ending March 31, 2018. In that case, the first such payment of approximately $5.55 million would be required to be paid during the fiscal quarter ending June 30, 2018. Any such mandatory prepayment would not, in and of itself, constitute a default under the Exit Facility.

Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility, at the Company’s option, will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4 — Long-Term Debt  – (continued)

three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after the Emergence Date.

Unused credit capacity under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears.

The Exit Facility is guaranteed by substantially all of the wholly-owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each Reorganized Debtor guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends.

The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis.

Further, the Company on March 3, 2017, entered into an amendment to the Exit Facility (the “Amendment”). The Amendment, among other things, includes updates necessary to reflect the Company changing its fiscal year end from June 30 to December 31. The Company was also required to deliver a December 31 reserve report prepared by a third-party engineer by March 1 of each year (or by May 31 with respect to 2017 only) and a reserve report prepared by the Company’s engineers by September 1 of each year. A second amendment and waiver to the Exit Facility (the “Second Amendment”) was entered into by the Company on April 24, 2017. The Second Amendment amends the requirement for the 2017 third-party reservoir engineer reserve report “as of” date from January 1, 2017 to April 1, 2017. Additionally, the Amendment also revises the calculation of: (i) the net present value of the future net revenues expected to accrue to the proved reserves of the Company and its subsidiaries and (ii) the asset coverage ratio, which is calculated by removing the effects of derivative agreements with any counterparties that are not lenders under the Exit Facility. Furthermore, the requirement for the Company and its subsidiaries to have mortgages covering at least 90% of the total value of their proved reserves was amended to require the mortgages to cover at least 90% of the revised net present value of the proved reserves.

As of June 30, 2017, we had approximately $74 million in borrowings and $202.8 million in letters of credit issued under the Exit Facility.

4.14% Promissory Note

In September 2012, the Predecessor entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note, which is secured by such other property and equipment, we were required to make a monthly payment of approximately $52,000 and were to pay one lump-sum payment of $3.3 million at maturity in October 2017. This note carries an interest rate of 4.14% per annum.

In accordance with the Plan, on the Emergence Date, all outstanding obligations under the promissory note were reinstated.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 4 — Long-Term Debt  – (continued)

Interest Expense

Interest expense consisted of the following (in thousands):

		Successor				Predecessor				Successor				Predecessor
		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016				Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Exit Term Loan		$	1,034			$	—			$	1,813			$	—
Exit Revolving Facility			2,402				—				5,227				—
Prepetition Revolving Credit Facility			—				4,223				—				8,142
11.0% Second Lien Notes due 2020			—				5,681				—				45,447
8.25% Senior Notes due 2018			—				637				—				7,250
6.875% Senior Notes due 2024			—				357				—				2,832
3.0% Senior Convertible Notes due 2018			—				388				—				3,291
7.50% Senior Notes due 2021			—				645				—				5,108
7.75% Senior Notes due 2019			—				283				—				2,242
9.25% Senior Notes due 2017			—				834				—				10,839
4.14% Promissory Note due 2017			36				—				74				41
Amortization of debt issue cost – Revolving Credit Facility			—				358				—				3,879
Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020			—				—				—				2,135
Accretion of original debt issue discount, 11.0% Second Lien Notes due 2020 – accelerated			—				—				—				44,855
Amortization of debt issue cost – 11.0% Second Lien Notes due 2020			—				—				—				1,724
Amortization of debt issue cost – 11.0% Second Lien Notes due 2020 – accelerated			—				—				—				36,243
Amortization of fair value premium – 8.25% Senior Notes due 2018			—				1,230				—				(2,095	)
Amortization of fair value premium – 8.25% Senior Notes due 2018 – accelerated			—				(1,231	)			—				(7,961	)
Amortization of debt issue cost – 6.875% Senior Notes due 2024			—				—				—				62
Amortization of debt issue cost – 6.875% Senior Notes due 2024 – accelerated			—				—				—				1,946
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018			—				—				—				2,941
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 – accelerated			—				—				—				33,370
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018			—				—				—				377
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 – accelerated			—				—				—				4,271
Amortization of debt issue cost – 7.50% Senior Notes due 2021			—				—				—				123
Amortization of debt issue cost – 7.50% Senior Notes due 2021 – accelerated			—				—				—				2,822
Amortization of debt issue cost – 7.75% Senior Notes due 2019			—				—				—				38
Amortization of debt issue cost – 7.75% Senior Notes due 2019 – accelerated			—				—				—				491
Amortization of debt issue cost – 9.25% Senior Notes due 2017			—				—				—				517
Amortization of debt issue cost – 9.25% Senior Notes due 2017 – accelerated			—				—				—				913
Derivative instruments financing and other			170				33				362				363
		$	3,642			$	13,438			$	7,476			$	212,206

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 5 — Asset Retirement Obligations

The following table describes the changes to our asset retirement obligations (in thousands):

Balance as of December 31, 2016 (Successor)		$	753,364
Liabilities acquired			—
Liabilities incurred			2,040
Liabilities settled			(27,491	)
Revisions*			(135,079	)
Accretion expense			22,447
Total balance as of June 30, 2017 (Successor)			615,281
Less: current portion			61,766
Long-term portion as of June 30, 2017 (Successor)		$	553,515

Note 6 — Derivative Financial Instruments

We enter into derivative transactions to reduce exposure to fluctuations in the price of crude oil and natural gas with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We have historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in our derivative portfolio. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying consolidated balance sheets. Any gains or losses resulting from changes in fair value of our outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.

Most of our crude oil production is sold at Heavy Louisiana Sweet. We have historically included contracts indexed to NYMEX-WTI, ICE Brent futures and Argus-LLS futures in our derivative portfolio to closely align and manage our exposure to the associated price risk.

On March 14, 2016, the fourteenth amendment to the Prepetition Revolving Credit Facility became effective and required us to unwind certain derivative transactions and use the proceeds therefrom to repay amounts of outstanding loans to EPL under the Prepetition Revolving Credit Facility, and for such repayments to then result in an automatic and permanent reduction in EXXI Ltd’s borrowing base. Accordingly, on March 15, 2016, EXXI Ltd unwound and monetized all of its outstanding crude oil and natural gas contracts and $50.6 million was applied to reduce amounts outstanding under the Prepetition Revolving Credit Facility.

In February 2017, we entered into costless collar contracts benchmarked to Argus-LLS, to hedge 10,000 BPD of our crude oil production for the period from March 2017 to December 2017 with an average floor price of $52.30 and an average ceiling price of $57.43. In May 2017, we entered into fixed price swap contracts benchmarked to NYMEX-WTI, to hedge 1,500 BPD of our crude oil production for the period from June 2017 to October 2017 and 3,500 BPD of our crude oil production for November 2017 and December 2017 with an average fixed price swap of $51.74.

With a costless collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. In a fixed price swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the swap fixed price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap fixed price.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Derivative Financial Instruments  – (continued)

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of derivative arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

As of June 30, 2017, we had the following net open crude oil derivative positions:

Remaining Contract Term		Type of Contract				Index				Volumes (MBbls)				Weighted Average Contract Price
														Swaps				Collars
																		Floor				Ceiling
July 2017 – December 2017			Collars				Argus-LLS				1,840				—			$	52.30			$	57.43
July 2017 – December 2017			Swaps				NYMEX-WTI				398			$	51.75				—				—

The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):

		Asset Derivative Instruments																Liability Derivative Instruments
		June 30, 2017								December 31, 2016								June 30, 2017								December 31, 2016
		Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value				Balance Sheet Location				Fair Value
Derivative financial instruments			Current			$	11,566				Current			$	—				Current			$	1,096				Current			$	—
			Non- Current				—				Non- Current				—				Non- Current				—				Non- Current				—
Total gross derivative financial instruments subject to enforceable master netting agreement							11,566								—								1,096								—
Derivative financial instruments			Current				(1,096	)			Current				—				Current				(1,096	)			Current				—
			Non- Current				—				Non- Current				—				Non- Current				—				Non- Current				—
Gross amounts offset in Balance Sheets							(1,096	)							—								(1,096	)							—
Net amounts presented in Balance Sheets			Current				10,470				Current				—				Current				—				Current				—
			Non- Current				—				Non- Current				—				Non- Current				—				Non- Current				—
						$	10,470							$	—							$	—							$	—

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 6 — Derivative Financial Instruments  – (continued)

The following table presents information about the components of the gain on derivative financial instruments (in thousands).

		Successor				Predecessor				Successor				Predecessor
Gain on derivative financial instruments		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016				Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Cash settlements, net of purchased put premium amortization		$	2,351			$	—			$	2,640			$	17,511
Proceeds from monetizations			—				—				—				50,588
Non-cash gain (loss) in fair value			7,061				—				10,470				(61,325	)
Total gain on derivative financial instruments		$	9,412			$	—			$	13,110			$	6,774

We monitor the creditworthiness of our counterparties who are also a part of our bank lending group. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. As of June 30, 2017, we had no collateral deposits with our counterparties.

Note 7 — Income Taxes

On the Emergence Date, the Predecessor Company engaged in several internal restructuring transactions that: (i) assigned all of Predecessor’s assets (directly or indirectly) to EGC, and (ii) separated EXXI Ltd, Energy XXI (US Holdings) Limited (Bermuda), Energy XXI, Inc., and Energy XXI USA from EGC. This had the effect, among other things, of isolating the original parent-level equity ownership and certain intercompany loans (the “Intercompany Loans”) from EGC. Then, pursuant to the Plan, the prepetition notes other than the 4.14% promissory note of $5.5 million, the Prepetition Revolving Credit Facility and 100% of the EGC stock owned by Energy XXI USA, Inc., were cancelled. Additionally, new EGC shares and warrants were issued to former creditors as set out in the Plan. Absent an exception, a debtor recognizes Cancellation of Indebtedness Income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (the “Tax Code”) provides that a debtor in a bankruptcy case (such as the Chapter 11 Cases) may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the Plan (the “Tax Attribute Reduction Rules”). The amount of CODI realized by a taxpayer is the adjusted issue price of any indebtedness discharged less the sum of (i) the amount of cash paid, (ii) the issue price of any new indebtedness issued and (iii) the fair market value of any other consideration, including equity, issued. As a result of the market value of equity upon emergence from the Chapter 11 Cases, the amount of CODI realized was approximately $2,600 million, which reduced the Company’s U.S. net operating loss (“NOL”) carryovers of $403 million to zero, and further reduced the Company’s tax basis in producing properties (subject to future recovery through tax DD&A deductions) and its investment in the stock of EPL by $2,197 million. This reduction in tax attributes occurred on the Convenience Date, the first day of the Company’s first tax year subsequent to the Emergence Date, as one effect of the Plan was to terminate the Predecessor’s fiscal income tax reporting period on the Emergence Date.

As a result of the fresh start accounting, virtually all historic deferred tax assets and liabilities were eliminated, including the accrued outbound 30% withholding tax on the Intercompany Loans from the Predecessor’s Bermuda parent, as these obligations were extinguished in the Plan and are not obligations of

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(Unaudited)

Note 7 — Income Taxes  – (continued)

the Successor entities. With the NOL carryover being reduced by the Tax Attribute Reduction Rules, the principal deferred tax assets and liabilities of the Successor after fresh-start accounting relate to our oil and gas properties. The remaining tax bases of our oil and natural gas properties are less than their respective book carrying values as determined in fresh-start accounting such that we have recorded a deferred tax liability for those properties. We have recorded a deferred tax asset for the asset retirement obligation (which has no tax basis and will be tax deductible or result in additional tax basis in assets when settled) and other items that exceed the deferred tax liability for oil and natural gas properties. As such, we recorded a valuation allowance of $174.5 million at December 31, 2016, which results in no net deferred tax asset or liability appearing on our statement of financial position. We recorded this valuation allowance at this date after an evaluation of all available evidence (including our recent history of Predecessor losses) that led to a conclusion that based upon the more-likely-than-not standard of the accounting literature, these deferred tax assets were unrecoverable.

Tax Code Sections 382 and 383 provide an annual limitation with respect to the ability of a corporation to utilize its tax attributes, including as the tax basis in certain assets (net unrealized built-in-losses), against future U.S. taxable income in the event of a change in ownership. The Company’s emergence from the Chapter 11 Cases was considered a change in ownership for purposes of Tax Code Section 382. The limitation under the Tax Code is based on the value of the loss corporation as of the Convenience Date, which reflects value after giving effect to the Plan’s steps. However, this and prior ownership changes and resulting annual limitation will have limited, if any, effect on the Company’s NOLs since all of the NOLs were extinguished by the Tax Attribute Reduction Rules. There is the possibility of deferral of recognition of certain portions of tax DD&A by the Tax Attribute Reduction Rules that would affect the timing of offsetting future taxable income, but would not affect income tax expense. No cash income taxes were paid during the period ended June 30, 2017, and, based upon current commodity pricing and planned development activity, no cash income taxes are expected for the year ending December 31, 2017.

We have estimated our effective income tax rate (benefit) for the year to be zero, as we are forecasting a pre-tax loss at this time. We do not believe that our net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time; as such, we have increased our valuation allowance by $6 million in the quarter ended June 30, 2017 to reflect the tax effect of this loss. This $6 million second quarter valuation allowance increase, when coupled with the $22 million first quarter valuation allowance increase, results in a valuation allowance of $28 million at June 30, 2017, after adjustments of $3 million for changes in estimate to the Fresh Start valuation allowance based on subsequent tax filings for pre-Effective Date periods with the Internal Revenue Service. A post-Emergence Date pre-tax NOL of approximately $99 million resulting from our post-Emergence Date losses represents our only NOL carryforwards. This post-Emergence Date NOL is not subject to limitation in future usage by the ownership changes rules of Tax Code section 382 or the Tax Attribute Reduction Rules resulting from the Plan, but cannot be carried back to pre-Emergence Date years to create a cash income tax refund.

Note 8 — Stockholders’ Equity

On the Emergence Date, the Company’s certificate of incorporation and bylaws were amended and restated in their entirety. Under our certificate of incorporation, the total number of all shares of capital stock that we are authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share.

On the Emergence Date, the Company entered into a registration rights agreement (the “Registration Rights Agreement”) with certain holders representing 10% or more of the Company’s common stock outstanding on that date or who acquire 10% or more of the Company’s common stock outstanding within six months of the Emergence Date (the “Holders”). The Registration Rights Agreement provided resale registration rights for the Holders’ Registerable Securities (as defined in the Registration Rights Agreement).

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 8 — Stockholders’ Equity  – (continued)

On February 28, 2017, in accordance with the requirements of the Registration Rights Agreement, the Company filed a registration statement on Form S-3 relating to the resale of an aggregate of 9,272,285 shares of our common stock, which may be offered for sale from time to time by the selling stockholders named in Form S-3 prospectus. The number of shares the selling stockholders may sell consists of 9,049,929 shares of common stock that are currently issued and outstanding and 222,356 shares of common stock that they may receive if they exercise their warrants. The selling stockholders acquired all of the shares of common stock and warrants covered by the Form S-3 prospectus in a distribution pursuant to Section 1145 under the United States Bankruptcy Code in connection with our plan of reorganization that became effective on the Emergence Date. We are not selling any shares of common stock under the Form S-3 prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The registration statement on Form S-3 was declared effective as of March 23, 2017.

On February 28, 2017, pursuant to our satisfaction of all the listing requirements, our common stock began trading on NASDAQ under the symbol “EXXI” at the opening of business.

During the three months ended June 30, 2017, we issued 9,833 shares of our common stock upon accelerated vesting of restricted stock units granted to one of our former board members.

As of June 30, 2017, 33,221,427 shares of common stock and 2,119,889 warrants were outstanding.

Note 9 — Supplemental Cash Flow Information

The following table presents our supplemental cash flow information (in thousands):

		Successor				Predecessor
		Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Cash paid for interest		$	7,484			$	33,634
Cash paid for income taxes			—				—

The following table presents our non-cash investing and financing activities (in thousands):

		Successor				Predecessor
		Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Changes in capital expenditures and accrued liabilities in accounts payable		$	(164	)		$	(65,560	)
Inventory transferred to oil and natural gas properties			—				7,081
Changes in asset retirement obligations			(133,039	)			24,228
Changes in other property and equipment			(455	)			—
Proceeds from monetization of derivative instruments applied to Prepetition Revolving Credit Facility			—				50,588

Note 10 — Employee Benefit Plans

As of the Emergence Date, the Company entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the compensation for the Company’s officers, directors, employees and consultants (the “Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP is 1,859,552 shares (or 5% of the total new equity). The compensation committee (the “Committee”) of the board of directors of the Company (the “Board”) generally administers the 2016 LTIP

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 10 — Employee Benefit Plans  – (continued)

and will determine the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP will be awarded to the Service Providers selected in the discretion of the Committee; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated no later than 120 days after the Emergence Date. As of April 29, 2017, the 3% of total new equity had been allocated by the Board.

Under the 2016 LTIP, stock options are issued with an exercise price that is not less than the fair market value of our common stock on the date of grant and expire 10 years from the grant date. Stock options that have been granted to date generally vest ratably over a three-year period. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that uses assumptions related to expected term, expected volatility, risk free rate and dividend yield. During the three and six months ended June 30, 2017, we granted 183,973 and 372,597 stock options, at a weighted average exercise price of $28.30 and $28.92 per stock option, respectively. As of June 30, 2017, 11,287 stock options were forfeited and we had 361,310 unvested stock options and $3.2 million in unrecognized compensation cost related to unvested stock options.

Under the 2016 LTIP, restricted stock units may be granted from time to time as approved by the Committee. To date, the restricted stock units granted by the Committee have a vesting date up to three years from the date of grant and each restricted stock unit represents a right to receive one share of our common stock. During the three and six months ended June 30, 2017, we granted 451,140 and 660,510 restricted stock units at a weighted average price of $27.70 and $23.51 per restricted stock unit, respectively, including 118,408 restricted stock units granted to members of the Board pursuant to the terms of the 2016 LTIP and the non-employee director compensation policy. As of June 30, 2017, 20,167 restricted stock units were forfeited and we had 610,740 unvested restricted stock units and $14.0 million in unrecognized compensation cost related to unvested restricted stock units.

Note 11 — Related Party Transactions

On February 2, 2017, John D. Schiller, Jr., Bruce W. Busmire and Antonio de Pinho resigned as President and CEO, Chief Financial Officer and Chief Operating Officer, respectively.

In connection with Mr. Schiller’s termination of employment, the employment-related provisions of Mr. Schiller’s Executive Employment Agreement, dated as of December 30, 2016 (the “Schiller Employment Agreement”) were terminated as of February 2, 2017. Under the Schiller Employment Agreement, Mr. Schiller was entitled to receive the following benefits, subject to his entry into a waiver and release agreement (i) a lump-sum cash severance payment in the amount of $2 million, and (ii) reimbursement for the monthly cost of maintaining health benefits for Mr. Schiller and his spouse and eligible dependents as of the date of his termination for a period of 18 months to the extent Mr. Schiller elects Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”) continuation coverage, less applicable taxes and withholding. The $2 million cash severance payment was made on April 3, 2017, the 60^th day after the termination date. Payments and benefits are subject to Mr. Schiller’s continued compliance with certain confidentiality, non-competition, non-solicitation and non-disparagement provisions of the waiver and release agreement. In addition on February 2, 2017, we entered into a consulting agreement (the “Schiller Consulting Agreement”) with Mr. Schiller, pursuant to which Mr. Schiller has agreed to serve as a special advisor to the Board during a transition period of up to six months. In consideration for those services, we have agreed to pay Mr. Schiller a consulting fee of $50,000 per month for up to six months.

Prior to their departure from the Company, Mr. Busmire and Mr. de Pinho were not party to employment agreements with us, nor did they participate in a severance plan. We paid Mr. Busmire and Mr. de Pinho

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 11 — Related Party Transactions  – (continued)

severance payments on February 15, 2017 in the amount of $750,000 each, less applicable taxes and withholdings, in consideration for the performance of the terms and conditions set forth in their Resignation Agreement and General Release, including, without limitation, a general release and non-disparagement provision. We have also agreed to reimburse Mr. Busmire and Mr. de Pinho for the monthly cost of maintaining health benefits for Mr. Busmire and Mr. de Pinho and their respective spouses and eligible dependents as of the date of their termination for a period of 18 months to the extent Mr. Busmire and Mr. de Pinho elect COBRA continuation coverage.

During the years ended June 30, 2015 and 2014, Mr. Schiller borrowed funds from personal acquaintances or their affiliates, certain of whom provide services to us. During the three and six months ended June 30, 2017 certain of those lenders provided services to the Company totaling $0.8 million and $2.3 million, respectively, and during the three and six months ended June 30, 2016 certain of those lenders provided services to the Company totaling $0.4 million and $3.7 million, respectively. During 2014, one of the directors on the Predecessor Board made a personal loan to Mr. Schiller at a time prior to becoming a member of the Predecessor Board but while a managing director at Mount Kellett Capital Management LP, which at the time owned a majority interest in Energy XXI M21K, LLC and 6.3% of EXXI Ltd’s common stock.

Note 12 — Loss per Share

Basic loss per share of common stock is computed by dividing net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be anti-dilutive, the diluted earnings per share calculation includes the impact of restricted stock, stock options and other common stock equivalents. The following table sets forth the calculation of basic and diluted loss per share (“EPS”) (in thousands, except per share data):

		Successor				Predecessor				Successor				Predecessor
		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016				Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Net loss		$	(23,643	)		$	(195,552	)		$	(88,958	)		$	(34,776	)
Preferred stock dividends			—				352				—				2,730
Net loss attributable to common stockholders		$	(23,643	)		$	(195,904	)		$	(88,958	)		$	(37,506	)
Weighted average shares outstanding for basic EPS			33,237				97,540				33,234				96,728
Add dilutive securities			—				—				—				—
Weighted average shares outstanding for diluted EPS			33,237				97,540				33,234				96,728
Loss per share
Basic and Diluted		$	(0.71	)		$	(2.01	)		$	(2.68	)		$	(0.39	)

The Company’s restricted stock units granted to the members of the Board during the three and six months ended June 30, 2017 are treated as outstanding for basic loss per share calculations since these shares are entitled to participate in dividends declared on common shares, if any, and undistributed earnings. As participating securities, the shares of restricted stock are included in the calculation of basic EPS using the two-class method. For the three and six months ended June 30, 2017, no earnings was allocated to the participating securities.

For the three and six months ended June 30, 2017 1,732,397 and 1,531,424 common stock equivalents, respectively, and for the three and six months ended June 30, 2016, 7,397,686 and 8,003,998 common stock equivalents, respectively, were excluded from the diluted average shares calculation.

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 13 — Commitments and Contingencies

Litigation.  We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.

On June 17, 2016, the SEC filed a proof of claim against EXXI Ltd asserting a general unsecured claim in the amount of $3.9 million based on alleged violations of the federal securities laws by EXXI Ltd pertaining to the failure to disclose; (i) certain funds borrowed by our former President and CEO John D. Schiller, Jr. from personal acquaintances or their affiliates, certain of which provided EXXI Ltd and certain of its subsidiaries with services, (ii) a personal loan made to Mr. Schiller by one of the directors on the Predecessor Board at a time prior to becoming a member of the Predecessor Board, (iii) Mr. Schiller’s pledge of EXXI Ltd stock to a certain financial institution and (iv) certain perquisites and compensation to Mr. Schiller, including in connection with certain expense reimbursements. The SEC’s claim against EXXI Ltd has been classified as a general unsecured claim to be paid, if at all, its pro rata share of the approximately $1.5 million General Unsecured Claim Distribution defined in the Plan, and, as such, is subject to the Settlement, Release, Injunction, and Related Provisions contained in Article VIII of the Plan, and also is subject to the Confirmation Order. The Debtors anticipate that they will object to the SEC’s claim.

Letters of Credit and Performance Bonds.  As of June 30, 2017, we had $337.9 million of performance bonds outstanding and $200 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico.

We are a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”) and our operations on these leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the BOEM. These leases require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws. In particular, compliance with lease requirements includes responsibility for decommissioning obligations such as the cost to plug and abandon wells, decommission and remove platforms and pipelines, and clear the seafloor of obstructions at the end of production. The BOEM generally requires that lessees post substantial bonds or other acceptable financial assurances that such obligations will be met.

In April 2015, the Predecessor received letters from the BOEM stating that certain of its subsidiaries no longer qualified for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. Accordingly, as of June 30, 2017, approximately $185.8 million of our performance bonds are lease and/or area bonds issued to the BOEM, to which the BOEM has access to assure our commitment to comply with the terms and conditions of those leases. As of June 30, 2017, we also maintain approximately $152.1 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies for wells and facilities pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. As of June 30, 2017, we had $49.7 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors.

To address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April 2015 and thereafter, the Predecessor submitted a long-term financial assurance plan (the “Long-Term Plan”) to the agency. The BOEM agreed to, and executed, the Long-Term Plan on February 25, 2016. The Predecessor submitted a proposed plan amendment on June 28, 2016 that would revise the executed Long-Term Plan (the “Proposed Plan Amendment”). We are currently awaiting the BOEM’s response to the Proposed Plan Amendment. However, since the BOEM’s issuance of the new NTL in July 2016 relating to the need for additional security to satisfy decommissioning obligations, the agency has made two separate announcements to offshore lessees, advising of a six-month extension to the implementation timeline under the NTL (unless there is a substantial risk of nonperformance) for provision of financial assurance for “non-sole

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 13 — Commitments and Contingencies  – (continued)

liability” properties (that is, leases, rights-of-way and rights of use and easements with multiple lessees, grant holders and/or assignors), and advising of the temporary withdrawal of orders requiring additional financial assurance for “sole liability” properties (that is, leases, rights-of-way and rights of use and easements with only one lessee or grant holder and no assignors), respectively (collectively, the January 2017 and February 2017 announcements are referred to as the “BOEM Early 2017 Announcements”). The purpose behind those announcements was for the BOEM to further review the complex financial assurance program requirements. Most recently, on May 1, 2017, the Secretary of the Interior issued Order 3350, directing the BOEM to promptly complete a review of the NTL and provide its comments on whether to implement this NTL. In furtherance of this directive, the BOEM announced on June 22, 2017 that it was extending the NTL implementation timeline as reflected in the BOEM Early 2017 Announcements beyond June 30, 2017, except in circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. BOEM’s review of the NTL consistent with Order 3350 is on-going.

We continue to work with the BOEM in finalizing a process under the Long-Term Plan and the Proposed Plan Amendment for providing adequate levels of financial assurance to satisfy the BOEM with respect to its April 2015 supplemental bonding letter and any subsequent concerns and guidance. The future cost of compliance with our existing supplemental bonding requirements could materially and adversely affect our financial condition, cash flows, and results of operations as we may be required to provide cash collateral to support the issuance of such bonds or other surety. If we are unable to provide additional required bonds as requested, the BSEE or the BOEM may have any of our operations on federal leases suspended or cancelled or otherwise impose monetary penalties.

Drilling Rig Commitments.  As of June 30, 2017, we have approximately $9.6 million committed under three drilling rig contracts. The contracts’ terms range from July 1, 2017 through December 31, 2017.

Other.  We maintain restricted escrow funds as required by certain contractual arrangements. At June 30, 2017, our restricted cash primarily related to $25.6 million in cash collateral associated with our bonding requirements and approximately $6 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field which will be transferred to the buyer of our interests in that field.

We and our oil and natural gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.

Note 14 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 14 — Fair Value of Financial Instruments  – (continued)

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and certain notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. The carrying value of the Exit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments historically consisted of financially settled crude oil and natural gas puts, swaps, put spreads, costless collars and three way collars. We estimated the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published London Interbank offered rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 6 — “Derivative Financial Instruments.”

The fair values of our restricted stock units are based on the period-end stock price. For our stock options, we utilize the Black-Scholes-Merton model to determine fair value, which incorporates various assumptions listed here to value the stock option awards. The dividend yield on our common stock was zero. The expected volatility is based on comparable companies’ asset volatilities. The risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant.

During the six months ended June 30, 2017 and the six month transition period ended December 31, 2016, we did not have any transfers from or to any level within the fair value hierarchy. The following table presents the fair value of our Level 2 financial instruments (in thousands):

		Successor
		Level 2
		As of June 30, 2017				As of December 31, 2016
Assets:
Oil and Natural Gas Derivatives		$	11,566			$	—
Liabilities:
Oil and Natural Gas Derivatives		$	1,096			$	—

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ENERGY XXI GULF COAST, INC.
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 14 — Fair Value of Financial Instruments  – (continued)

The following table sets forth the outstanding and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments (in thousands):

		Successor
		June 30, 2017								December 31, 2016
		Carrying Value				Estimated Fair Value				Carrying Value				Estimated Fair Value
Exit Facility		$	73,996			$	73,996			$	73,996			$	73,996
		$	73,996			$	73,996			$	73,996			$	73,996

Note 15 — Prepayments and Accrued Liabilities

Prepayments and other current assets and accrued liabilities consist of the following (in thousands):

		Successor
		June 30, 2017				December 31, 2016
Prepaid expenses and other current assets
Advances to joint interest partners		$	1,424			$	650
Insurance			8,348				9,600
Inventory			916				470
Royalty deposit			1,401				1,273
Prepaid professional fees			—				4,584
Prepaid ONRR annual inspection fees			2,251				—
Prepaid software license fees			1,351				—
Other			1,485				9,380
Total prepaid expenses and other current assets		$	17,176			$	25,957
Accrued liabilities
Advances from joint interest partners			374				374
Employee benefits and payroll			5,418				4,491
Interest payable			220				233
Undistributed oil and gas proceeds			13,375				22,715
Severance taxes payable			827				628
Restructuring expenses			—				25,712
East Bay field restricted cash payable			6,050				6,036
General and administrative and legal expenses payable			6,170				3,456
Other			2,083				15
Total accrued liabilities		$	34,517			$	63,660

Note 16 — Subsequent Events

In August 2017, we entered into fixed price swap contracts benchmarked to NYMEX-WTI, to hedge 2,000 BPD of our crude oil production for the period from January 2018 to December 2018 with an average fixed price of $49.52.

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements we make in this quarterly report on Form 10-Q (the “Quarterly Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Regarding Forward-Looking Statements” and Part I “Item 1A. Risk Factors” included in our 2016 Transition Report and elsewhere in this Quarterly Report.

Overview

We are headquartered in Houston, Texas and have historically engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and offshore in the Gulf of Mexico Shelf (“GoM Shelf”), which is an area in less than 1,000 feet of water.

We have historically focused on development and extension drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by exploration and strategic acquisitions from time to time. Our acquisition strategy has historically been to target mature, oil-producing properties on the GoM Shelf and the U.S. Gulf Coast that have not been thoroughly exploited by prior operators. We believe these activities will provide us with an inventory of low-risk recompletion and drilling opportunities in our geographic area of expertise.

Our geographic concentration on the GoM Shelf enables us to realize service cost synergies. By having operations in a geographically concentrated area, we can optimize helicopter and boat charters to more efficiently service our operations. In addition, our size may provide us with opportunities to place service work out to bid to obtain better services and prices.

At March 31, 2017, our total SEC proved reserves were 109.4 MMBOE of which 80% were oil, 2% were natural gas liquids and 18% were natural gas and 71% were classified as proved developed reserves. We operated or had an interest in 616 gross producing wells on 439,294 net developed acres, including interests in 57 producing fields. We believe operating our assets is a key to our success and approximately 90% of our proved reserves are on properties operated by us. Our geographical concentration on the GoM Shelf enables us to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves.

Emergence from Chapter 11

On April 14, 2016, EXXI Ltd, an exempt company incorporated under the laws of Bermuda and predecessor of the Reorganized EGC, EGC, EPL, then an indirect wholly-owned subsidiary of EXXI Ltd and certain other indirect wholly-owned subsidiaries of EXXI Ltd filed voluntary petitions for reorganization in the Bankruptcy Court seeking relief under the provisions of Chapter 11.

On December 13, 2016, the Bankruptcy Court entered the Confirmation Order, and on December 30, 2016, the Debtors emerged from bankruptcy.

On the Emergence Date, the Debtors satisfied the conditions to effectiveness, the Plan became effective in accordance with its terms and the Debtors emerged from Chapter 11 Cases. In connection therewith, EXXI Ltd and its subsidiaries completed a series of internal reorganization transactions pursuant to which EXXI Ltd transferred all of its remaining assets to Reorganized EGC, as the new parent entity. Accordingly, Reorganized EGC succeeded to the entire business and operations previously consolidated for accounting purposes by EXXI Ltd. In accordance with ASC 852, the Reorganized EGC applied fresh start accounting upon the Predecessor’s emergence from bankruptcy and it evaluated transaction activity between the Emergence Date and December 31, 2016 and concluded that an accounting convenience date of December 31, 2016 (the “Convenience Date”) was appropriate.

For reporting purposes, the pre-reorganization predecessor reflects the business that was transferred to the Reorganized EGC. The financial statements of the pre-reorganization predecessor are EXXI Ltd’s consolidated financial statements.

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Recent Developments

NASDAQ Listing

On February 1, 2017, the Company filed a Current Report on Form 8-K12G3 as its initial report of the Company to the SEC and as notice that the Company is the successor issuer to EXXI Ltd under Rule 12g-3 under the Exchange Act. On February 24, 2017 the Company filed a registration statement on Form 8-A, pursuant to which its common stock is deemed to be registered under Section 12(b) of the Exchange Act. At the opening of business on February 28, 2017, our common stock began trading on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI”.

Departure and Appointment of Company Directors and Officers

On February 2, 2017, John D. Schiller, Jr. resigned from his position as President and Chief Executive Officer (“CEO”) of the Company and also ceased to serve as a member of the Board of Directors of the Company (the “Board”). As a result, on February 2, 2017, the Board appointed Michael S. Reddin, the Company’s Chairman of the Board, to serve as the Company’s President and CEO on an interim basis, while continuing to serve as Chairman of the Board. Because Mr. Reddin was serving both as Chairman of the Board and CEO, the Board amended and restated the Company’s bylaws to provide for a Lead Independent Director and appointed director James W. Swent III to serve in that capacity. On April 17, 2017, we entered into an employment agreement with Douglas E. Brooks (the “Brooks Employment Agreement”), pursuant to which Mr. Brooks became our CEO and President effective as of April 17, 2017.

Upon the Board’s appointment of Mr. Brooks as CEO and President, Mr. Reddin ceased serving in those two interim roles. Under the terms of Mr. Reddin’s employment agreement relating to those two interim roles, Mr. Reddin served as an employee (but not as CEO or President) until May 17, 2017, which was the 30^th day after Mr. Brooks’ appointment. Mr. Swent served as the Lead Independent Director until May 17, 2017.

In order to eliminate the Board vacancy created by Mr. Schiller’s departure from the Board, the size of the Board was reduced from seven to six directors on February 2, 2017. In connection with the Board’s approval of the Brooks Employment Agreement, the Board increased the size of the Board from six to seven directors and appointed Mr. Brooks to fill the newly-created directorship on April 17, 2017.

Additionally, on February 2, 2017, Bruce W. Busmire and Antonio de Pinho resigned as Chief Financial Officer (“CFO”) and Chief Operating Officer (“COO”), respectively. As a result, on February 2, 2017, the Board appointed Scott M. Heck as the Company’s new COO to succeed Mr. de Pinho and appointed Hugh A. Menown, the Company’s current Executive Vice President and Chief Accounting Officer, as the Company’s CFO on an interim basis to succeed Mr. Busmire.

Fiscal Year Change

On February 7, 2017, the Board adopted a resolution to change the Company’s fiscal year end from June 30 to December 31. As a result, the 2016 Transition Report included financial information for the transition period from July 1, 2016 through December 31, 2016. Subsequent to the 2016 Transition Report, our reports on Form 10-K will cover the calendar year, January 1 to December 31, which will be our fiscal year.

Shelf Registration

On February 28, 2017, the Company filed a registration statement on Form S-3 relating to the resale of an aggregate of 9,272,285 shares of our common stock, which may be offered for sale from time to time by the selling stockholders named in Form S-3 prospectus. The number of shares the selling stockholders may sell consists of 9,049,929 shares of common stock that were currently issued and outstanding and 222,356 shares of common stock that they may receive if they exercise their warrants. The selling stockholders acquired all of the shares of common stock and warrants covered by the Form S-3 prospectus in a distribution pursuant to Section 1145 under the Bankruptcy Code in connection with the Plan. We are not selling any shares of common stock under such prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The registration statement on form S-3 was declared effective as of March 23, 2017.

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Strategic Plan

On March 20, 2017 the Company announced that it had retained Morgan Stanley & Co. LLC to assist the Board and senior management team with the evaluation, development and implementation of a strategic plan, including a stand-alone financial plan and select strategic alternatives. We continue to work on our long-term strategic plan and are evaluating a variety of alternatives with our financial advisors.

March 31, 2017 Reserves and Impairment

The Company engaged Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”) to prepare estimates of our proved reserves as of March 31, 2017. Pursuant to the terms of our Exit Facility, a third party engineer report is required annually, with the first report due by May 31, 2017. The first NSAI report was delivered by us on May 23, 2017. The estimates of proved crude oil and natural gas reserves attributable to our net interests in oil and gas properties as of March 31, 2017 utilizing SEC 12-month average pricing of $47.62 per barrel of oil and $2.73 per MMBTU, before differentials were 109.4 MMBOE of which 80% were oil, 2% were natural gas liquids and 18% were natural gas and 71% were classified as proved developed reserves with a PV-10 value (the net present value, determined using a discount rate of 10% per annum, of the future net revenues expected to accrue to the proved reserves of the Company and its subsidiaries) of $108.4 million resulting in a decrease in proved reserves and PV-10 value of 12.5 MMBOE and $27 million, respectively as of March 31, 2017 compared to the estimated proved reserves and PV-10 value of 121.9 MMBOE and $135.4 million, respectively, prepared by our internal reservoir engineers as of December 31, 2016. The primary non-commodity price factors contributing to the difference between the NSAI March 31, 2017 SEC reserve report and the internally-prepared December 31, 2016 SEC reserve report are: (i) technical reassessments, (ii) higher capital costs and (iii) production during the first quarter of 2017. The impact of those factors was partially offset by higher SEC average commodity prices for both crude oil and natural gas. As a result of these changes, as of March 31, 2017, we incurred an impairment of our oil and natural gas properties of $44.1 million.

Fiscal 2017 Plans

For the remainder of fiscal year 2017, the Company intends to focus on:

Operational Update

The Company implemented additional work force reductions to lower its overhead costs and better align its staffing with its current expected operational plans. Total headcount was reduced by approximately 18% which resulted in severance and separation expenses of approximately $2.5 million during the three months ended June 30, 2017. The Company expects to realize a total of approximately $8 million to $8.5 million of annualized general and administrative and lease operating expense savings from this reduction.

The first well in our 2017 development program, the West Delta 30 L-14 ST2 High Tide well was spud on June 7, 2017. This well was drilled to a total vertical depth of 8,500 feet. We expect to complete this well in the third quarter of fiscal 2017. The Company operates and has a 100% working interest in this well.

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In July 2017, we spud our second well, the West Delta 31 L-19 ST1 Kingstream. However, the Company has ceased drilling operations due to unexpected drilling difficulties. The Company has temporarily abandoned the wellbore, but is evaluating future plans to potentially re-drill the well from a different location to avoid the area that is causing the drilling challenges. The Company operates and has a 100% working interest in this well. Our current fiscal 2017 development plan is focused on the West Delta area and to drill two wells.

The Company was added to the Russell 3000® Index effective after the US market opened on June 26, 2017. We believe that addition to the Russell 3000® Index will provide greater awareness among institutional investors, while providing additional liquidity to our shares.

Known Trends and Uncertainties

Commodity Price Volatility and Impact on our Results of Operations.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil and natural gas prices declined significantly during 2015 and the decline continued with lower prices into 2016. Although oil prices briefly rebounded to average above $50.00 per barrel in April 2017, there is still significant volatility in commodity prices and the prices have declined to an average of $46.68 in July 2017. These prices are significantly lower than the industry has experienced in recent years. Further declines in oil and natural gas prices may adversely affect our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce due to natural declines and limited activity in the fields. If the prices of oil and natural gas continue to be at lower levels or further decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected.

Reduced Capital Spending.   With the continued market instability from July 2014 through the first half of 2017, numerous exploration and production (“E&P”) companies have been forced to stop drilling new wells — the core of an E&P company’s business — and cut capital expenditures, as it is not economically feasible to undertake capital intensive projects. For fiscal year 2017, the Company’s revised capital budget, excluding acquisitions but including plugging and abandonment is expected to be in the range of $125 million to $155 million total, of which plugging and abandonment costs are expected to be in the range of $50 million to $70 million.

Reserve Quantities.   A prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio. At March 31, 2017, our total proved reserves were 109.4 MMBOE. The unweighted arithmetic average of first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period used to determine our reserves as of March 31, 2017 was $46.32 per barrel of oil, $23.58 per barrel of NGLs and $2.57 per MCF of natural gas.

Ceiling Test Write-down.   For the three months ended June 30, 2017, we reduced the impairment of our oil and natural gas properties by $0.8 million to reflect the correction of an immaterial error in certain asset retirement obligations included in the first quarter 2017 impairment calculation; however, as a result of the decrease in proved reserves and PV-10 value relative to the estimated reserves prepared by our internal reservoir engineers as of December 31, 2016, our ceiling test computation as of March 31, 2017 resulted in an impairment of our oil and natural gas properties of $44.1 million. Further ceiling test write-downs will be required if oil and natural gas prices decline, unevaluated property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and natural gas properties otherwise exceeds the present value of estimated future net cash flows.

Service Costs Fluctuations.   Due to the depressed commodity price environment, there has been a significant and continuing reduction in rig rates and drilling costs, which has allowed us to spend less capital on drilling our development wells. However, the cost to hire an experienced drilling crew and source critical oil-field supplies may increase if the price of oil increases.

BOEM Supplemental Financial Assurance and/or Bonding Requirements.   As of June 30, 2017, we had $337.9 million of performance bonds outstanding and $200 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”) in April 2015, the Predecessor received letters from the BOEM stating that certain of its subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for

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potential offshore decommissioning, plugging and abandonment liabilities. Accordingly, as of June 30, 2017, approximately $185.8 million of our performance bonds are lease and/or area bonds issued to the BOEM, to which the BOEM has access to assure our commitment to comply with the terms and conditions of those leases. As of June 30, 2017, we also maintain approximately $152.1 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies for wells and facilities pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. As of June 30, 2017, we had $49.7 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors. We continue to work with the BOEM in finalizing a process under the long-term financial assurance plan (the “Long-Term Plan”) and the proposed plan amendment submitted on June 28, 2016 that would revise the executed Long-Term Plan (the “Proposed Plan Amendment”) for providing adequate levels of financial assurance to satisfy the BOEM with respect to its April 2015 supplemental bonding letter and any subsequent concerns and guidance. If we are unable to provide additional required bonds as requested, the Bureau of Safety and Environmental Enforcement (“BSEE”) or the BOEM may have any of our operations on federal leases suspended or cancelled or otherwise impose monetary penalties. Such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Oil Spill Response Plan.   We maintain a Regional Oil Spill Response Plan (the “OSRP”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are approved by the BSEE. The OSRP is reviewed annually and updated as necessary, which updates also require BSEE approval. The OSRP specifications are consistent with the requirements set forth by the BSEE. Additionally, the OSRP is tested and drills are conducted bi-annually at all levels of the Company.

We have contracted with a spill response management consultant to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico that has the appropriate equipment and access to appropriate personnel to simultaneously respond to multiple spills. In the event of a spill, CGA mobilizes appropriate equipment and personnel to CGA members.

Hurricanes.   Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

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Operational Information

						Successor												Predecessor
						Quarter Ended								On December 31, 2016				Quarter Ended
Operating Highlights						June 30, 2017				March 31, 2017								December 31, 2016				September 30, 2016				June 30, 2016
		(In thousands, except per unit amounts)
Operating revenues
Oil sales						$	118,180			$	133,621			$	—			$	132,308			$	122,732			$	130,083
Natural gas liquids sales							2,370				2,227				—				1,389				2,144				2,996
Natural gas sales							13,753				18,368				—				19,368				17,735				14,725
Gain on derivative financial instruments							9,412				3,698				—				—				—				—
Total revenues							143,715				157,914				—				153,065				142,611				147,804
Percentage of oil revenues prior to gain on derivative financial instruments							88	%			87	%			—				86	%			86	%			88	%
Operating expenses
Lease operating expense
Insurance expense							7,101				6,250				—				6,287				6,309				8,269
Workover and maintenance							13,370				10,005				—				11,705				11,010				17,471
Direct lease operating expense							64,865				58,902				—				53,845				47,851				51,063
Total lease operating expense							85,336				75,157				—				71,837				65,170				76,803
Production taxes							482				239				—				268				214				155
Gathering and transportation							13,172				21,716				—				8,541				17,699				14,260
Depreciation, depletion and amortization							38,661				42,006				—				29,053				31,573				40,078
Accretion of asset retirement obligations							10,050				12,397				—				19,536				19,437				18,905
Impairment of oil and natural gas properties							(848	)			44,054				406,275				—				86,820				142,640
General and administrative							20,716				21,604				—				12,122				15,435				23,174
Reorganization items							(3,773	)			2,244				—				—				—				—
Total operating expenses							163,796				219,417				406,275				141,357				236,348				316,015
Operating (loss) income						$	(20,081	)		$	(61,503	)		$	(406,275	)		$	11,708			$	(93,737	)		$	(168,211	)
Sales volumes per day
Oil (MBbls)							26.8				29.1				—				29.6				30.0				31.4
Natural gas liquids (MBbls)							1.0				0.9				—				0.5				1.3				1.5
Natural gas (MMcf)							48.9				65.9				—				73.8				72.8				86.5
Total (MBOE)							35.9				41.0				—				42.5				43.4				47.3
Percent of sales volumes from oil							75	%			71	%			—				70	%			69	%			66%

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						Successor												Predecessor
						Quarter Ended								On December 31, 2016				Quarter Ended
Operating Highlights						June 30, 2017				March 31, 2017								December 31, 2016				September 30, 2016				June 30, 2016
		(In thousands, except per unit amounts)
Average sales price
Oil per Bbl						$	48.45			$	51.04			$	—			$	48.54			$	44.52			$	45.55
Natural gas liquid per Bbl							27.37				27.52								28.50				18.12				21.55
Natural gas per Mcf							3.09				3.10				—				2.85				2.65				1.87
Gain on derivative financial instruments per Bbl							2.88				1.00				—				—				—				—
Total revenues per BOE							43.99				42.83				—				39.19				35.73				34.32
Operating expenses per BOE
Lease operating expense
Insurance expense							2.17				1.70				—				1.61				1.58				1.92
Workover and maintenance							4.09				2.71				—				3.00				2.76				4.06
Direct lease operating expense							19.85				15.98				—				13.79				11.99				11.86
Total lease operating expense per BOE							26.11				20.39				—				18.40				16.33				17.84
Production taxes							0.15				0.06				—				0.07				0.05				0.04
Gathering and transportation							4.03				5.89				—				2.19				4.43				3.31
Depreciation, depletion and amortization							11.83				11.39				—				7.44				7.91				9.31
Accretion of asset retirement obligations							3.08				3.36				—				5.00				4.87				4.39
Impairment of oil and natural gas properties							(0.26	)			11.95				—				—				21.75				33.12
General and administrative							6.34				5.86				—				3.10				3.87				5.38
Reorganization items							(1.15	)			0.61				—				—				—				—
Total operating expenses per BOE							50.13				59.51				—				36.20				59.21				73.39
Operating (loss) income per BOE						$	(6.14	)		$	(16.68	)		$	—			$	2.99			$	(23.48	)		$	(39.07	)

Results of Operations

The three and the six months ended June 30, 2017 (Successor Company) and the three and the six months ended June 30, 2016 (Predecessor Company) are distinct reporting periods as a result of our application of fresh-start accounting upon our emergence from Chapter 11 on December 30, 2016 and may not be comparable to one another or to prior periods.

Three Months Ended June 30, 2017 and Three Months Ended June 30, 2016

Our consolidated net loss attributable to common stockholders for the three months ended June 30, 2017 was $23.6 million or $0.71 diluted loss per common share (“per share”). Net loss for the three months ended June 30, 2017 was primarily due to lower oil and natural gas sales volumes.

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Our consolidated net loss attributable to common stockholders for the three months ended June 30, 2016 was $195.9 million or $2.01 diluted loss per share. Net loss for the three months ended June 30, 2016 was primarily due to the impairment of oil and natural gas properties and incurring reorganization expenses.

Revenues

		Successor				Predecessor
		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016
		(In thousands)
Oil		$	118,180			$	130,083
Natural gas liquids			2,370				2,996
Natural gas			13,753				14,725
Gain on derivative financial instruments			9,412				—
Total Revenues		$	143,715			$	147,804

Our consolidated revenues were $143.7 million and $147.8 million during the three months ended June 30, 2017 and 2016, respectively. The decrease in revenues was primarily due to lower oil, natural gas liquids and natural gas sales volumes, partially offset by higher realized prices for oil, natural gas liquids and natural gas sales and gain on derivative financial instruments. Revenue related to commodity prices, sales volumes and derivative activities are presented in the following table and described below.

Price and Volume

		Successor				Predecessor
		Three Months Ended June 30, 2017				Three Months Ended June 30, 2016
Price
Oil sales prices (per Bbl)		$	48.45			$	45.55
Natural gas liquids sales prices (per Bbl)			27.37				21.55
Natural gas sales prices (per Mcf)			3.09				1.87
Gain on derivative financial instruments (per Bbl)			2.88				—
Volume
Oil sales volumes (MBbls)			2,439				2,856
Natural gas liquids volumes (MBbls)			87				139
Natural gas sales volumes (MMcf)			4,448				7,875
BOE sales volumes (MBOE)			3,267				4,307
Percent of BOE from oil			75	%			66	%

Price

Commodity prices are one of the key drivers of our earnings and net operating cash flow. For the three months ended June 30, 2017, our realized oil price was $48.45 per Bbl, $27.37 per Bbl for natural gas liquids, $3.09 per Mcf for natural gas and $2.88 per Bbl gain on derivative financial instruments. For the three months ended June 30, 2016, our realized oil price was $45.55 per Bbl, $21.55 per Bbl for natural gas liquids and $1.87 per Mcf for natural gas. Commodity prices are inherently volatile and are affected by many factors that are outside of our control and we cannot accurately predict future commodity prices.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. For the three months ended June 30, 2017 our oil sales volumes were 26.8 MBbls per day, natural gas liquids sales volumes were 1 MBbls per day and the natural gas sales volumes were 48.9 MMcf per day. For the three months ended June 30, 2016 our oil sales volumes were 31.4 MBbls per day, natural gas liquids sales volumes were

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1.5 MBbls per day and the natural gas sales volumes were 86.5 MMcf per day. Sales volumes decreased because of natural well production declines, reduced drilling activity resulting in less new production, and increased downtime due to shutdown of third party pipelines for repairs and maintenance.

Costs and Expenses and Other (Income) Expense

		Successor								Predecessor
		Three Months Ended June 30, 2017								Three Months Ended June 30, 2016
		Total				Per BOE				Total				Per BOE
		(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense
Insurance expense		$	7,101			$	2.17			$	8,269			$	1.92
Workover and maintenance			13,370				4.09				17,471				4.06
Direct lease operating expense			64,865				19.85				51,063				11.86
Total lease operating expense			85,336				26.11				76,803				17.84
Production taxes			482				0.15				155				0.04
Gathering and transportation			13,172				4.03				14,260				3.31
Depreciation, depletion and amortization			38,661				11.83				40,078				9.31
Accretion of asset retirement obligations			10,050				3.08				18,905				4.39
Impairment of oil and natural gas properties			(848	)			(0.26	)			142,640				33.12
General and administrative			20,716				6.34				23,174				5.38
Reorganization items			(3,773	)			(1.15	)			—				—
Total costs and expenses		$	163,796			$	50.13			$	316,015			$	73.39
Other (income) expense
Other income, net			(80	)			(0.02	)			(160	)			(0.04	)
Interest expense			3,642				1.11				13,438				3.12
Total other expense, net		$	3,562			$	1.09			$	13,278			$	3.08

Lease operating expenses on a per BOE basis were $26.11 and $17.84 for the three months ended June 30, 2017 and 2016, respectively. The total lease operating expense increased primarily due to increased well activity and return to normal operating margins charged by our vendors. Lease operating expense per BOE increased by $8.27 per BOE primarily due to lower production volumes.

Gathering and transportation on a per BOE basis were $4.03 and $3.31 for the three months ended June 30, 2017 and 2016, respectively. Gathering and transportation expense per BOE increased primarily due to lower production volumes.

Depreciation, depletion and amortization (“DD&A”) expense on a per BOE basis was $11.83 and $9.31 for the three months ended June 30, 2017 and 2016, respectively. The DD&A expense recorded for the three months ended June 30, 2017 is not comparable to other periods due to the measurement of assets at their fair value upon emergence from bankruptcy and the impact of impairments of oil and natural gas properties recognized in prior periods.

Accretion of asset retirement obligations on a per BOE basis was $3.08 and $4.39 for the three months ended June 30, 2017 and 2016, respectively. The accretion expense recorded for the three months ended June 30, 2017 is not comparable to other periods due to the measurement of asset retirement obligations at their fair value upon emergence from bankruptcy.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs) to our net capitalized costs of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted

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future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. For the three months ended June 30, 2017, we reduced the impairment of our oil and natural gas properties by $0.8 million to reflect the correction of an immaterial error in certain asset retirement obligations included in the first quarter 2017 impairment calculation. For the three months ended June 30, 2016, the ceiling test computation resulted in impairment of the Predecessor’s oil and natural gas properties of $142.6 million, primarily related to declining prices.

General and administrative expenses on a per BOE basis were $6.34 and $5.38 for the three months ended June 30, 2017 and 2016, respectively. The decrease in total general and administrative expense was primarily due to lower employee salary costs, legal expenses, rent expense and restructuring costs, partially offset by higher stock-based compensation and increase in severance and separation costs of approximately $2.5 million. General and administrative expense per BOE increased due to lower production volumes.

During the three months ended June 30, 2017, the credit of $3.8 million to the reorganization items reflects the correction of immaterial errors to the fresh start accounting opening balance sheet related to asset retirement obligations and other property, plant and equipment. These errors were not deemed material with respect to the prior year, the three months ended June 30, 2017 or the anticipated results for the fiscal year 2017.

Interest expense on a per BOE basis was $1.11 and $3.12 for the three months ended June 30, 2017 and 2016, respectively. The decrease in interest expense was primarily due to the elimination of interest on all of the Predecessor’s prepetition notes which were cancelled on the Emergence Date other than the 4.14% promissory note of $5.5 million.

Income Tax Expense

We do not believe that our net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time; accordingly, our net increase in valuation allowance for the three months ended June 30, 2017 was $6 million. We recorded no income tax expense for the three months ended June 30, 2016 primarily due to the forecast book loss for the year and our inability to currently record any additional net deferred tax assets due to a preponderance of negative evidence as to future realizability of these deferred tax assets.

Six Months Ended June 30, 2017 and Six Months Ended June 30, 2016

Our consolidated net loss attributable to common stockholders for the six months ended June 30, 2017 was $89.0 million or $2.68 diluted loss per share. Net loss for the six months ended June 30, 2017 was primarily due to the impairment of oil and natural gas properties and lower oil and natural gas sales volumes.

Our consolidated net loss attributable to common stockholders for the six months ended June 30, 2016 was $37.5 million or $0.39 diluted loss per share. Net loss for the six months ended June 30, 2016 was primarily due to the impairment of oil and natural gas properties, higher interest expense and reorganization costs, partially offset by the gain on early extinguishment of debt.

Revenues

		Successor				Predecessor
		Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
		(In thousands)
Oil		$	251,801			$	222,275
Natural gas liquids			4,597				5,885
Natural gas			32,121				29,155
Gain on derivative financial instruments			13,110				6,774
Total Revenues		$	301,629			$	264,089

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Our consolidated revenues were $301.6 million and $264.1 million during the six months ended June 30, 2017 and 2016, respectively. The increase in revenues was primarily due to higher realized prices for oil, natural gas liquids and natural gas sales and higher gain on derivative financial instruments, partially offset by lower oil, natural gas liquids and natural gas sales volumes. Revenue related to commodity prices, sales volumes and derivative activities are presented in the following table and described below.

Price and Volume

		Successor				Predecessor
		Six Months Ended June 30, 2017				Six Months Ended June 30, 2016
Price Variance
Crude oil sales prices (per Bbl)		$	49.79			$	38.00
Natural gas liquids sales prices (per Bbl)			27.44				17.83
Natural gas sales prices (per Mcf)			3.10				1.87
Gain on derivative financial instruments (per Bbl)			1.89				0.77
Volume Variance
Crude oil sales volumes (MBbls)			5,057				5,849
Natural gas liquids volumes (MBbls)			168				330
Natural gas sales volumes (MMcf)			10,375				15,588
BOE sales volumes (MBOE)			6,954				8,777
Percent of BOE from crude oil			73	%			67	%

Price

For the six months ended June 30, 2017, our realized oil price was $49.79 per Bbl, $27.44 per Bbl for natural gas liquids, $3.10 per Mcf for natural gas and $1.89 per Bbl gain on derivative financial instruments. For the six months ended June 30, 2016, our realized oil price was $38.00 per Bbl, $17.83 per Bbl for natural gas liquids, $1.87 per Mcf for natural gas and $0.77 per Bbl gain on derivative financial instruments. Commodity prices are inherently volatile and are affected by many factors that are outside of our control and we cannot accurately predict future commodity prices.

Volume Variances

For the six months ended June 30, 2017 our oil sales volumes were 27.9 MBbls per day, natural gas liquids sales volumes were 0.9 MBbls per day and the natural gas sales volumes were 57.3 MMcf per day. For the six months ended June 30, 2016 our oil sales volumes were 32.1 MBbls per day, natural gas liquids sales volumes were 1.8 MBbls per day and the natural gas sales volumes were 85.7 MMcf per day. Sales volumes decreased because of natural well production declines, reduced drilling activity resulting in less new production, and increased downtime due to shutdown of third party pipelines for repairs and maintenance.

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Costs and Expenses and Other (Income) Expense

		Successor								Predecessor
		Six Months Ended June 30, 2017								Six Months Ended June 30, 2016
		Total $				Per BOE				Total $				Per BOE
		(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense
Insurance expense		$	13,351			$	1.92			$	16,581			$	1.89
Workover and maintenance			23,375				3.36				29,576				3.37
Direct lease operating expense			123,767				17.80				108,266				12.34
Total lease operating expense			160,493				23.08				154,423				17.60
Production taxes			721				0.10				376				0.04
Gathering and transportation			34,888				5.02				32,839				3.74
DD&A			80,667				11.60				93,925				10.70
Accretion of asset retirement obligations			22,447				3.23				33,962				3.87
Impairment of oil and natural gas properties			43,206				6.21				483,109				55.04
General and administrative			42,320				6.09				51,532				5.87
Reorganization items			(1,529	)			(0.22	)			—				—
Total costs and expenses		$	383,213			$	55.11			$	850,166			$	96.86
Other (income) expense
Other income, net			(102	)			(0.01	)			(548	)			(0.06	)
Gain on early extinguishment of debt			—				—				(777,022	)			(88.53	)
Interest expense			7,476				1.08				212,206				24.18
Total other (income) expense, net		$	7,374			$	1.07			$	(565,364	)		$	(64.41	)