UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10‑Q

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

For the quarterly period ended June 30, 2018

OR

☐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)

(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 ☑    No ☐

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 ☑    No ☐

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):

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

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

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 ☑    No ☐

As of August 3, 2018, there were 33,396,563 shares outstanding of the registrant’s common stock, par value $0.01 per share.

ENERGY XXI GULF COAST, INC.

TABLE OF CONTENTS

GLOSSARY OF TERMS

Industry Terms

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

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.

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.

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 activity undertaken to increase value or realize full value in oil and natural gas field.

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 or natural gas to the point of sale.

GoM Shelf is an area offshore on the U.S. Gulf of Mexico continental shelf, generally characterized by less than 1,000 feet of water.

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

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

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

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.

NGL refers to natural gas liquids.

Oil includes crude oil and condensate.

Pipeline facility fee is the straight line lease expense attributable to certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM Shelf and storage and onshore processing facilities at Grand Isle, Louisiana (“GIGS”).

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 and the removal of associated equipment. 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 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 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)(3) of Regulation S-X as promulgated by the SEC.

Proved undeveloped 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)(4) of Regulation S-X as promulgated by the SEC.

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.

Unevaluated properties refer to properties for which a determination has not been made as to whether the property contains proved reserves.

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

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.

Other Terms

Tax Code means the Internal Revenue Code of 1986, as amended, including changes made by the Tax Cuts and Jobs Act of 2017 (as defined below).

Tax Cuts and Jobs Act of 2017 refers to tax legislation commonly referred to as the Tax Cuts and Jobs Act of 2017, enacted on December 22, 2017.

INTRODUCTORY NOTE REGARDING EGC’S PENDING MERGER

On June 18, 2018, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with MLCJR LLC (“Cox”), a Texas limited liability company and an affiliate of Cox Oil LLC, and YHIMONE, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Cox (“Merger Sub”). Upon the terms and conditions set forth in the Merger Agreement, at the consummation of the transactions contemplated by the Merger Agreement, Merger Sub will be merged with and into EGC (the “Merger”), and EGC will survive the Merger as the surviving corporation and an indirect wholly-owned subsidiary of Cox.

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each issued and outstanding share of EGC common stock, par value $0.01 per share (“Common Stock”), will be converted into the right to receive $9.10 in cash without interest (the “Merger Consideration”).

Closing Conditions.  The completion of the Merger is subject to satisfaction or waiver of certain closing conditions, including: (i) approval of the Merger Agreement by EGC’s stockholders, (ii) there being no law or injunction prohibiting consummation of the Merger; (iii) subject to specified materiality standards, the accuracy of the representations and warranties of the other party; (iv) compliance by the other party in all material respects with its covenants; and (v) the absence of a material adverse effect on the other party.  The completion of the Merger is not conditioned on receipt of financing by Cox.

Termination Rights.  The Merger Agreement contains certain termination rights for both EGC and Cox and further provides that, upon termination of the Merger Agreement, under certain circumstances, EGC may be required to pay Cox a termination fee equal to $8 million and, in certain other circumstances, EGC may be required to reimburse Cox for its documented out-of-pocket expenses up to $2 million.

Interim Operating Covenants.  EGC has agreed to certain covenants in the Merger Agreement restricting the conduct of its business between the date of the Merger Agreement and the Effective Time.  The effect of these covenants is that, until the Merger is consummated, EGC will be very limited in its ability to pursue strategic and operational initiatives outside the ordinary course of business.  Therefore, if the Merger Agreement is terminated and the Merger does not occur, it will need to renew the financing, cost-cutting, and liability management initiatives that it had been pursuing prior to the execution of the Merger Agreement.

In general, EGC has agreed to conduct its business in the ordinary course, consistent with past practice and use all commercially reasonable efforts to preserve intact its present business organization, retain its officers and key employees, and preserve its relationships with its customers and suppliers and other persons having significant business dealings with it, to the end that its goodwill and ongoing business will not be impaired in any material respect.  EGC has also agreed to comply, in all material respects, with all applicable law, except where the failure to comply would not reasonably likely to have, individually or in the aggregate, a material adverse effect, and to not voluntarily resign, transfer or relinquish any right as operator of its oil and gas properties.

In addition, EGC has agreed to specific restrictions relating to the conduct of its business between the date of the Merger Agreement and the Effective Time, including, but not limited to, not to take (or permit any of its subsidiaries to take) the following actions (subject, in each case, to exceptions specified below and in the Merger Agreement or previously disclosed in writing to Cox as provided in the Merger Agreement or as consented to in advance by Cox (which consent shall not be unreasonably withheld, delayed or conditioned) or as required by law or in the event of certain emergencies):

Special Stockholder Meeting.  As stated in EGC’s definitive proxy statement (the “Merger Proxy Statement”) filed with the SEC on  August 3, 2018, EGC will hold a special meeting of its stockholders on September 6, 2018 at 9 a.m. (Houston Time).  At that special meeting, EGC stockholders will be asked to vote on the adoption of the Merger Agreement, which requires the affirmative vote of the holders of two-thirds of the issued and outstanding shares of Common Stock entitled to vote at the EGC special meeting. The record date for the special meeting is August 3, 2018.  Therefore, in order to be entitled to notice of, and to vote at, the special meeting or any adjournment or postponement of the special meeting, an individual or entity must be the record holder of shares of Common Stock at the close of business on August 3, 2018.

Anticipated Timing; No Assurance that Closing will Occur.  The Merger is expected to close in the third quarter of 2018.  However, EGC cannot provide any assurance the combination will be completed on the terms or timeline currently contemplated, or at all.

The above is a summary of certain material terms of the Merger Agreement and is qualified in its entirety by the terms and conditions of the Merger Agreement, which was filed as an exhibit to the Company’s current report on Form 8-K filed on June 18, 2018.

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.

These forward-looking statements relate to the transactions contemplated by the Merger Agreement, as well as to EGC’s financial and operating performance on a stand-alone basis prior to the consummation of the Merger or if the Merger is not consummated.  Important factors that could cause actual results and outcomes to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:

Forward-Looking Statements Relating to the Merger

Forward-Looking Statements Relating to EGC’s Financial and Operating Performance

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 annual report on Form 10‑K for the fiscal year ended December 31, 2017 (the “2017 Annual 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.

PART I – FINANCIAL INFORMATION

ITEM 1.   Unaudited Consolidated Financial Statements

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

See accompanying Notes to Consolidated Financial Statements.

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, except per share information)

(Unaudited)

See accompanying Notes to Consolidated Financial Statements.

ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

See accompanying Notes to Consolidated Financial Statements.

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization and Nature of Operations

Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) was formed in December 2016 after emerging from a voluntary reorganization under chapter 11 proceedings as the restructured successor of Energy XXI Ltd (“EXXI Ltd” or the “Predecessor”). The Company is headquartered in Houston, Texas, and engages in the development, exploitation, and operation of oil and natural gas properties primarily offshore in the GoM Shelf, which is an area in less than 1,000 feet of water, and also onshore in Louisiana and Texas. EGC owns and operates nine of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilizes various techniques to increase the recovery factor and thus increase the total oil recovered.

Note 2 — Recent Events

On June 18, 2018, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with MLCJR LLC (“Cox”), a Texas limited liability company and an affiliate of Cox Oil LLC, and YHIMONE, Inc., a Delaware corporation and a direct wholly-owned subsidiary of Cox (“Merger Sub”). Upon the terms and conditions set forth in the Merger Agreement, at the consummation of the transactions contemplated by the Merger Agreement, Merger Sub will be merged with and into EGC (the “Merger”), and EGC will survive the Merger as the surviving corporation and an indirect wholly-owned subsidiary of Cox.

Subject to the terms and conditions of the Merger Agreement, at the effective time of the Merger (the “Effective Time”), each issued and outstanding share of EGC common stock, par value $0.01 per share (“Common Stock”), will be converted into the right to receive $9.10 in cash without interest (the “Merger Consideration”).

Pursuant to the Merger Agreement, immediately prior to the Effective Time, the vesting of each outstanding EGC restricted stock unit (each, an “RSU”) will accelerate (if not already vested), with any performance conditions deemed achieved at target, and be cancelled and converted into the right to receive the Merger Consideration, multiplied by the number of shares of Common Stock subject to that RSU. 

The exercise price for each outstanding stock option is greater than the Merger Consideration. As a result, at the Effective Time, each stock option to purchase shares of Common Stock will be cancelled for no consideration.

In accordance with the warrant agreement under which the Company’s 2,119,889 outstanding warrants were issued, the warrants will no longer represent the right to acquire shares of Common Stock at the Effective Time.  Instead, at that time, each warrant will become exercisable for $9.10 in cash, but the warrant holder would be required to pay the warrant’s cash exercise price of $43.66 per share in order to receive $9.10.  Therefore, the Merger Agreement provides that, at the Effective Time, each outstanding warrant will be cancelled for no consideration.

The completion of the Merger is subject to satisfaction or waiver of certain closing conditions, including: (i) approval of the Merger Agreement by EGC’s stockholders, (ii) there being no law or injunction prohibiting consummation of the Merger; (iii) subject to specified materiality standards, the accuracy of the representations and warranties of the other party; (iv) compliance by the other party in all material respects with its covenants; and (v) the absence of a material adverse effect on the other party.  The completion of the Merger is not conditioned on receipt of financing by Cox.

EGC and Cox have made customary representations and warranties in the Merger Agreement. The Merger Agreement also contains customary covenants and agreements whereby EGC has agreed to (i) operate its business in the ordinary course; (ii) use its commercially reasonable efforts to maintain and preserve its present business organization, retain its officers and key employees, and preserve its relationships with its customers and suppliers; and (iii) subject to certain exceptions, not take certain actions relating to its dividends, capital stock or alternative business combinations, among other things, during the period between the execution of the Merger Agreement and the Effective Time. EGC and Cox have each agreed to use commercially reasonable efforts to cause the Merger to be completed.

The Merger Agreement contains certain termination rights for both EGC and Cox and further provides that, upon termination of the Merger Agreement, under certain circumstances, EGC may be required to pay Cox a termination fee

equal to $8 million and, in certain other circumstances, EGC may be required to reimburse Cox for its documented out-of-pocket expenses up to $2 million.

As stated in the Merger Proxy Statement, EGC will hold a special meeting of its stockholders on September 6, 2018 at 9 a.m. (Houston time). At that special meeting, EGC stockholders will be asked to vote on the adoption of the Merger Agreement, which requires the affirmative vote of the holders of two-thirds of the issued and outstanding shares of Common Stock entitled to vote at the EGC special meeting. The record date for the special meeting is August 3, 2018.  Therefore, in order to be entitled to notice of, and to vote at, the special meeting or any adjournment or postponement of the special meeting, an individual or entity must be the record holder of shares of Common Stock at the close of business on August 3, 2018.

The Merger is expected to close in the third quarter of 2018.  However, EGC cannot provide any assurance the combination will be completed on the terms or timeline currently contemplated, or at all.  The above is a summary of the material terms of the Merger Agreement and is qualified in its entirety by the terms and conditions of the Merger Agreement, which was filed as an exhibit to the Company’s current report on Form 8-K filed on June 18, 2018.

Shortly prior to entering into the Merger Agreement, the Company terminated its previously-disclosed non-binding term sheet with Orinoco Natural Resources, LLC and certain of its affiliates, which provided for the disposition of certain non-core assets, a cash payment, execution of a ten-year second lien note, issuance of common equity, execution of a ten-year master services agreement and a commitment to anchor a potential future financing plan. The termination fee for the term sheet was $1.0 million and was paid subsequent to June 30, 2018.

Note 3 – Summary of Significant Accounting Policies and Recent Accounting Pronouncements

Principles of Consolidation and Reporting. The accompanying consolidated financial statements on June 30, 2018 include the accounts of EGC 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. EGC’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The consolidated financial statements for the prior period include certain reclassifications to conform to the current presentation. Those reclassifications did not have any impact on the previously reported consolidated result of operations or cash flows.

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 the Company’s depletion rate for its proved oil and natural gas properties and the full cost ceiling test limitation. 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; among others. Accordingly, the Company’s accounting estimates require the exercise of judgment by management in preparing such estimates. While the Company believes 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 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 2017 Annual 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 the Company beginning in the first quarter of 2018. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the

related ASC, including guidance related to the use of the “entitlements” method of revenue recognition used by the Company.

The Company adopted ASC 606 effective January 1, 2018, which replaces previous revenue recognition requirements under FASB ASC Topic 605 – Revenue Recognition (“ASC 605”). The standard was adopted using the modified retrospective approach which requires the Company to recognize in retained earnings at the date of adoption the cumulative effect of the application of ASC 606 to all existing revenue contracts which were not substantially complete as of January 1, 2018. The Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying ASC 606.

Although the adoption of ASC 606 did not have an impact on the Company’s net loss or cash flows, it did result in the reclassification of certain fees received under pipeline gathering and transportation and pipeline tariff agreements that were previously included in oil sales to other revenue in the consolidated statements of operations. 

The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as lease operating expense and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. 

The Company receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable, oil and natural gas sales in the consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant.

The Company has elected to utilize the practical expedient in ASC 606 that states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our contracts, each monthly delivery of product represents a separate performance obligation, therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

The Company previously utilized the entitlements method to account for natural gas imbalances, which is no longer applicable under ASC 606. The impact to the financial statements resulting from this change in accounting for natural gas imbalances was not significant.

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, the Company enters into lease agreements to support operations. The Company is evaluating the provisions of ASU 2016‑02 to determine the quantitative effects it will have on its consolidated financial statements and related disclosures. The Company believes the adoption and implementation of this ASU will have a material impact on its balance sheet resulting from an increase in both assets and liabilities relating to its leasing activities.

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 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. The Company has not yet determined the effect of this standard on its 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”). ASU 2016‑15 provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The Company’s adoption of ASU 2016‑15 on January 1, 2018 using the retrospective transition method had no effect on its consolidated financial position, results of operations or cash flows other than presentation.

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. The Company’s adoption of ASU 2016‑18 on January 1, 2018 had no effect on its consolidated financial position, results of operations or cash flows other than presentation.

Note 4 – Property and Equipment

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

Under the full cost method of accounting, at the end of each financial reporting period, the Company compares 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. The Company refers 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, the Company is required to write down the value of oil and natural gas properties to the amount of the discounted cash flows.  For the six months ended June 30, 2018, the Company did not incur any impairment to its oil and natural gas properties.  For the three months ended June 30, 2018, the Company did not record an impairment to oil and natural gas properties.  For the six months ended June 30, 2017, the Company recorded impairment to oil and natural gas properties of $40.8 million.  The impairment to oil and natural gas properties for the six months ended June 30, 2017 was primarily due to the difference in SEC reserves and the related PV-10 value relative to the estimated reserves prepared by its internal reservoir engineers as of December 31, 2016.

Costs associated with unevaluated properties are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available.  For the three months and six months ended June 30, 2018, the costs associated with unevaluated properties decreased by $3.6 million and $7.9 million, respectively.  For the three months ended June 30, 2018, the decrease of $2.2 million was attributable to ratable amortization and $1.8 million was transferred to evaluated properties due to impairment, partially offset by an addition of $0.4 million related to exploratory drilling costs.  For the six months ended June 30, 2018, the decrease of $4.3 million was attributable to ratable amortization and $4.0 million was transferred to evaluated properties due to impairment, partially offset by an addition of $0.4 million related to exploratory drilling costs.

Note 5 – Long-Term Debt

As of June 30, 2018 and December 31, 2017 the Company’s outstanding debt consisted of the following (in thousands):

Exit Facility

On December 30, 2016, the Company entered into a secured Exit Facility, which matures on December 30, 2019. The Exit Facility, as amended, is secured by mortgages on at least 90% of the value of it and its subsidiary guarantors’ proved developed producing reserves as well as its total proved reserves. The Exit Facility consists of two facilities: (i) a term loan facility (the “Exit Term Loan”) and (ii) a revolving credit facility (the “Exit Revolving Facility”) for the making of revolving loans and the issuance of letters of credit.

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 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 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.

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.  On March 29, 2018, the Company prepaid $10.0 million outstanding under the Exit Term Loan.  No payment was made during the quarter ended June 30, 2018.  Due to a potential decline in its estimated trailing twelve-month EBITDA calculation for the twelve-month period ending September 30, 2018, the Company may prepay additional amounts of its outstanding Exit Term Loan in order to prevent a breach of the First Lien Leverage Ratio, and such a prepayment could adversely affect its liquidity.   Additionally, due to its decreased cash position, the Company may not meet its required Current Ratio (as defined in the Exit Facility).  Under those circumstances, the Company would explore several options to remain in compliance with the terms of the Exit Facility, including modifying the timing of its capital expenditures.

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 December 30, 2016 and (ii) the then outstanding principal amount of the Exit Term Loan. Based on the results of the quarter ended March 31, 2018, the Company made a mandatory prepayment of $5.5 million during the quarter ended June 30, 2018.  Based on the results of the quarter ended June 30, 2018, the Company will not be required to make a prepayment during the quarter ended September 30, 2018.  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 possible that it will be required to make a mandatory prepayment with respect to fiscal quarters subsequent to September 30, 2018. In the event of a mandatory prepayment, any such mandatory prepayment would not, in and of itself, constitute a default under the Exit Facility.  As of June 30, 2018, the Company is in compliance with all terms of the Exit Facility.

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

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.

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 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 December 30, 2016.

The Company currently has $12.5 million 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.

As of June 30, 2018, the Company had approximately $58.4 million in borrowings and $201.5 million in letters of credit issued under the Exit Facility.

Note 6 – Asset Retirement Obligations

The following table describes the changes to the Company’s asset retirement obligations (in thousands):

Note 7 – Derivative Financial Instruments

The Company enters 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. The Company has historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in its derivative portfolio.  With a costless collar, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price of the collar, and the Company was 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 the Company if the settlement price for any settlement period is below the swap fixed price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the swap fixed price.

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 (loss) gain on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.

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

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, 2018,  the Company had the following open crude oil derivative positions:

In April 2018, with no cash outlay, we unwound 3,000 BPD of our WTI swaps for the period from April 1, 2018 to June 30, 2018 and replaced the unwound swaps with 3,000 BPD ICE Brent swaps with an average swap price of $61.00 per Bbl for the period January 2019 to December 2019.  Additionally, we added 3,000 BPD ICE Brent costless collars with a floor price of $60.00 and a ceiling price of $82.00 for the period April 13, 2018 to June 30, 2018.

The fair values of derivative instruments in the Company’s consolidated balance sheets were as follows (in thousands):

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

The Company monitors the creditworthiness of its counterparties who are also a part of its bank lending group. However, the Company is not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer its position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of its financial counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices and could incur a loss. As of June 30, 2018,  the Company had no collateral deposits with our counterparties.

Note 8 – Income Taxes

No cash income taxes were paid during the three months and six months ended June 30, 2018, and, based upon current commodity pricing and planned development activity, no cash income taxes are expected to be paid or owed for the year ending December 31, 2018.

The Company has estimated its effective income tax rate for the year to be zero, as the Company is forecasting a pre-tax loss at this time. The Company does not believe that its net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time; as such, during the three months and six months ended June 30, 2018, the Company increased its valuation allowance by $5.9 million and $12.3 million, respectively, to reflect the tax effects of this loss. The $12.3 million valuation allowance increase for the six months ended June 30, 2018, when coupled with the $306.2 million valuation allowance at December 31, 2017, results in a valuation allowance of $318.6 million at June 30, 2018. The Company made no changes during the period to its deferred tax assets or valuation allowance related to the Tax Cuts and Jobs Act of 2017.

Note 9 – Stockholders’ Equity

Under the Company’s certificate of incorporation, the total number of all shares of capital stock that it is 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.

During the three months and six months ended June 30, 2018, we issued 128,085 shares and 141,600 shares, respectively, of our common stock upon vesting of RSUs and as of June 30, 2018, we had 33,396,563 shares of common stock,  285,105 stock options and 2,119,889 warrants outstanding.

Note 10 – Supplemental Cash Flow Information

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

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

The following table presents the reconciliation of cash, cash equivalents and restricted cash as presented on the consolidated statement of cash flows (in thousands):

Note 11 – Employee Benefit Plans

Long Term Incentive Plans

On December 30, 2016, the Company adopted 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 common stock reserved and available for delivery with respect to awards under the 2016 LTIP was 1,859,552 shares (or 5% of the total new equity). Awards under the 2016 LTIP are awarded to the Service Providers selected at the discretion of the compensation committee (the “Committee”) of the board of directors of the Company (the “Board”).  However, under the terms of the Energy XXI Ltd’s chapter 11 plan of reorganization, 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP had to be allocated by the Board no later than 120 days after December 30, 2016.  As of April 29, 2017, the 3% of total new equity had been allocated by the Board.

In order to retain key employees and attract new employees with the experience and skill sets that fit the Company’s culture and corporate strategy, the Board approved the Energy XXI Gulf Coast, Inc. 2018 Long Term Incentive Plan (the “2018 LTIP”) on April 11, 2018 and the Company’s stockholders approved the 2018 LTIP at the 2018 annual meeting of stockholders held on May 17, 2018.  Upon approval, the number of shares of common stock available for awards under the 2018 LTIP were (i) 1,860,000 plus (ii) the number of shares remaining available for award under the 2016 LTIP on the date of the 2018 annual meeting. As of June 30, 2018, there were  1,317,083 shares remaining available for award under the 2018 LTIP.  As a result of the adoption and stockholder approval of the 2018 LTIP, no additional equity awards or other long term incentive awards may be made under the 2016 LTIP.  However, existing awards that were granted under the 2016 LTIP will continue to be subject to the provisions of the 2016 LTIP.

The Compensation Committee generally administers the 2016 LTIP and the 2018 LTIP (together the “Company LTIPs”).  The Compensation Committee determines the types of equity based awards (which may include stock option, stock appreciation rights, RSUs, bonus stock awards, performance-based restricted stock units (each a “PBRSU”), other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards.

Under the Company LTIPs, stock options have been and may be 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. As of June 30, 2018, there were 285,105 unvested stock options and $0.9 million in unrecognized compensation cost related to unvested stock options.  The exercise price