Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1

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Exhibit 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

C O N T E N T S

	Page

Report of Independent Registered Public Accounting Firm		1

Consolidated Balance Sheets		2

Consolidated Statements of Income		3

Consolidated Statements of Comprehensive Income (Loss)		4

Consolidated Statements of Stockholder’s Equity		5

Consolidated Statements of Cash Flows		6

Notes to Consolidated Financial Statements		7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Energy XXI Gulf Coast, Inc.

We have audited the accompanying consolidated balance sheets of Energy XXI Gulf Coast, Inc. (a Delaware Corporation) and subsidiaries (the “Company”) as of June 30, 2014 and 2013, and the related consolidated statements of income, comprehensive income (loss), stockholder’s equity and cash flows for each of the three fiscal years in the period ended June 30, 2014. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI Gulf Coast, Inc. and subsidiaries as of June 30, 2014 and 2013, and the consolidated results of their operations and their cash flows for each of the three fiscal years in the period ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

/s/ UHY LLP

Houston, Texas

September 3, 2014

-1-

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	June 30,
	2014			2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	9,325		$	-
Receivables:
Oil and natural gas sales		167,075			132,521
Joint interest billings		12,898			9,505
Insurance and other		4,099			5,367
Prepaid expenses and other current assets		69,367			47,864
Deferred income taxes		52,011			-
Derivative financial instruments		1,425			38,389
TOTAL CURRENT ASSETS		316,200			233,646
Property and Equipment
Oil and gas properties-net – full cost method of accounting, including $1,165.7 million and $422.6 million of unevaluated properties not being amortized at June 30, 2014 and 2013, respectively		6,524,602			3,289,505
Other property and equipment		3,087			-
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		6,527,689			3,289,505
Other Assets
Goodwill		327,235			-
Note receivable from Energy XXI, Inc.		69,845			67,935
Derivative financial instruments		3,035			21,926
Restricted cash		6,350			-
Debt issuance costs, net of accumulated amortization		42,155			24,791
Total Other Assets		448,620			114,652
TOTAL ASSETS	$	7,292,509		$	3,637,803

LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	414,518		$	219,822
Accrued liabilities		85,162			58,334
Notes payable		21,967			22,349
Asset retirement obligations		79,649			29,500
Derivative financial instruments		31,957			40
Current maturities of long-term debt		14,094			18,838
TOTAL CURRENT LIABILITIES		647,347			348,883
Long-term debt, less current maturities		3,396,473			1,344,843
Deferred taxes		691,779			153,805
Asset retirement obligations		480,185			258,318
Derivative financial instruments		4,306			-
Other liabilities		2,454			-
TOTAL LIABILITIES		5,222,544			2,105,849
COMMITMENTS AND CONTINGENCIES (NOTE 11)
STOCKHOLDER’S EQUITY
Common stock, $0.01 par value, 1,000,000 shares
authorized and 100,000 shares issued and outstanding		1			1
Additional paid-in capital		2,092,438			1,426,349
Retained earnings (accumulated deficit)		(2,040	)		79,304
Accumulated other comprehensive (loss) income, net of
income taxes		(20,434	)		26,300
TOTAL STOCKHOLDER’S EQUITY		2,069,965			1,531,954

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	7,292,509		$	3,637,803

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

	Year Ended June 30,
	2014			2013			2012

REVENUES
Oil sales	$	1,091,223		$	1,080,982		$	1,186,631
Natural gas sales		139,502			127,863			116,772
TOTAL REVENUES		1,230,725			1,208,845			1,303,403

COSTS AND EXPENSES
Lease operating expense		365,747			337,163			310,815
Production taxes		5,427			5,246			7,261
Gathering and transportation		23,532			24,168			16,371
Depreciation, depletion and amortization		419,754			372,252			364,281
Accretion of asset retirement obligations		30,183			30,885			39,161
General and administrative expense		85,320			63,909			79,080
Loss (gain) on derivative financial instruments		5,704			1,915			(7,261	)
TOTAL COSTS AND EXPENSES		935,667			835,538			809,708

OPERATING INCOME		295,058			373,307			493,695

OTHER INCOME (EXPENSE)
Other income		1,958			1,860			1,192
Interest expense		(147,920	)		(108,360	)		(108,731	)
TOTAL OTHER EXPENSE		(145,962	)		(106,500	)		(107,539	)

INCOME BEFORE INCOME TAXES		149,096			266,807			386,156

INCOME TAX EXPENSE		52,124			83,431			71,010

NET INCOME	$	96,972		$	183,376		$	315,146

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)


	Year Ended June 30,
	2014			2013			2012
Net Income	$	96,972		$	183,376		$	315,146
Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		(61,683	)		(8,348	)		228,398
Effective portion reclassified to earnings during the period		(10,215	)		(39,810	)		(34,418	)
Total Other Comprehensive Income (Loss)		(71,898	)		(48,158	)		193,980
Income Tax Expense (Benefit)		(25,164	)		(16,855	)		67,893
Net Other Comprehensive Income (Loss)		(46,734	)		(31,303	)		126,087
Comprehensive Income	$	50,238		$	152,073		$	441,233

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In Thousands, except share information)


	Common Stock
	Shares		Value		Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholder’s Equity

Balance, June 30, 2011		100,000	$	1	$	1,456,517		$	(372,318	)	$	(68,484	)	$	1,015,716

Returns to parent						(2,436	)								(2,436	)

Comprehensive income									315,146			126,087			441,233

Balance, June 30, 2012		100,000		1		1,454,081			(57,172	)		57,603			1,454,513

Returns to parent						(27,732	)								(27,732	)

Dividends paid									(46,900	)					(46,900	)

Comprehensive income (loss)									183,376			(31,303	)		152,073

Balance, June 30, 2013		100,000		1		1,426,349			79,304			26,300			1,531,954

Contributions from parent						666,089			(3,216	)					662,873

Dividends paid									(175,100	)					(175,100	)

Comprehensive income (loss)									96,972			(46,734	)		50,238

Balance, June 30, 2014		100,000	$	1	$	2,092,438		$	(2,040	)	$	(20,434	)	$	2,069,965

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended June 30,
	2014			2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	96,972		$	183,376		$	315,146
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization		419,754			372,252			364,281
Deferred income tax expense (benefit)		52,124			83,431			71,161
Change in derivative financial instruments
Proceeds from sale of derivative instruments		-			635			66,522
Other		(1,793	)		(27,358	)		(52,335	)
Accretion of asset retirement obligations		30,183			30,885			39,161
Amortization and write-off of debt issuance costs		6,513			6,898			7,475
Amortization of debt discount and premium		-			-			148
Gain on retirement of debt		-			-			-
Payment of interest in-kind		-			-			-
Changes in operating assets and liabilities:
Accounts receivable		63,244			1,233			(4,390	)
Prepaid expenses and other current assets		4,637			3,377			(2,316	)
Settlements of asset retirement obligations		(57,391	)		(41,939	)		(14,990	)
Accounts payable and other liabilities		(72,646	)		61,669			(330	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		541,597			674,459			789,533

CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions, net of cash acquired		(849,641	)		(161,164	)		(6,401	)
Capital expenditures		(785,465	)		(804,918	)		(565,978	)
Insurance payments received		1,983			-			6,472
Proceeds from the sale of properties		126,265			-			2,750
Transfer to restricted cash		(325	)		-			-
Other-net		(3	)		(6	)		3
NET CASH USED IN INVESTING ACTIVITIES		(1,507,186	)		(966,088	)		(563,154	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		3,084,305			1,571,061			896,717
Contributions from (returns to) parent		170,568			(27,732	)		(2,436	)
Dividends paid		(175,100	)		(46,900	)		-
Advances to Energy XXI, Inc.		(1,910	)		(1,836	)		(66,099	)
Payments on long-term debt		(2,079,072	)		(1,243,545	)		(1,008,300	)
Debt issuance costs and other		(23,877	)		(4,813	)		(867	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		974,914			246,235			(180,985	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		9,325			(45,394	)		45,394

CASH AND CASH EQUIVALENTS, beginning of year		-			45,394			-

CASH AND CASH EQUIVALENTS, end of year	$	9,325		$	-		$	45,394

See accompanying Notes to Consolidated Financial Statements

-6-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations. Energy XXI Gulf Coast, Inc. (“Energy XXI”), a Delaware corporation, was incorporated on February 7, 2006 and is a wholly-owned subsidiary of Energy XXI USA, Inc. (its “Parent”). Energy XXI (Bermuda) Limited (“Bermuda”), indirectly owns 100% of Parent. Energy XXI (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and offshore in the Gulf of Mexico. References in this report to “us,” “we,” “our,” or “the Company,” are to Energy XXI and its wholly-owned subsidiaries.

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to current presentation. Such reclassifications have no impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated 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 our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require 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 difference may be material.

Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.

Restricted Cash. We maintain restricted escrow funds in a trust for future plugging, abandonment and other decommissioning costs. These funds will remain restricted until substantially all required decommissioning is complete. Amounts on deposit in the trust account are reflected in restricted cash on our consolidated balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2014 and 2013, no allowance for doubtful accounts was necessary.

Oil and Natural Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.

Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method.

-7-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Weather Based Insurance Linked Securities. We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense.

Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.

Business Combinations. For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.

In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.

Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.

Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in fiscal 2014 with the EPL Acquisition and has been recorded to our oil and natural gas reporting unit. Events affecting oil and natural gas prices may cause a decrease in the fair value of the reporting unit, and we could have an impairment of goodwill in future periods.

Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Gains or losses resulting from transactions designated as cash flow hedges are recorded at market value and are recorded, net of related tax impact, in Accumulated Other Comprehensive Income (“AOCI”) as appropriate, until recognized as operating income in our consolidated statement of income as the physical production hedged by the contracts is delivered. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized directly in earnings.

The net cash flows related to any recognized gains or losses associated with cash flow hedges are reported as oil and natural gas revenue and presented in cash flow from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contract is delivered.

Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the straight-line method, which approximates the interest method.

Asset Retirement Obligations. Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

-8-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Common Stock. Refers to the $0.01 par value per share capital stock as designated in the Company’s Certificate of Incorporation.

Revenue Recognition. We recognize oil and natural gas revenue under the entitlement method of accounting. Under the entitlement method, revenue is recorded when title passes based on our net interest. We record our entitled share of revenues based on entitled volumes and contracted sales prices.

Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.

When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements. At June 30, 2014 we maintained a $22.5 million valuation allowance against our net deferred tax assets due to our judgment that our existing State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax (at 30%) is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.

We adopted the provisions of ASC Topic 740-10 (formally known as FIN 48, addressing “Uncertain Tax Positions”) and applied this guidance as of July 1, 2007. As of the adoption date, we did not record a cumulative effect adjustment related to the adoption of ASC Topic 740-10 nor have we recorded any gross unrecognized tax benefit related to Uncertain Tax Positions.

Note 2 — Recent Accounting Pronouncements

In December 2011, the FASB issued Accounting Standards Update No. 2011-11 Balance Sheet: Disclosures about Offsetting Assets and Liabilities (ASU 2011-11). ASU 2011-11 requires that an entity disclose information about offsetting and related arrangements to enable users of its financial statements to understand the effect of those arrangements on its financial position. ASU 2011-11 is effective for annual periods beginning on or after January 1, 2013. We adopted ASU 2011-11 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In February 2013, the FASB issued Accounting Standards Update No. 2013-02: Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 updates ASU 2011-12 and requires companies to report information of significant changes in accumulated balances of each component of other comprehensive income included in equity in one place. Total changes in accumulated other comprehensive income by component can either be presented on the face of the financial statements or in the notes. ASU 2013-02 is effective for fiscal years and interim periods within those years beginning after December 15, 2012, with early adoption permitted. We adopted ASU 2013-02 on July 1, 2013 and the adoption had no effect on our consolidated financial position, results of operations or cash flows, other than presentation.

In July 2013 the FASB issued Accounting Standards Update No. 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU-2013-11). ASU 2013-11 clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. We are currently evaluating the provisions of ASU 2013-11 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

-9-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 3 – Acquisitions and Dispositions

ExxonMobil oil and gas properties interests acquisition

On October 17, 2012, we closed on the acquisition of certain shallow-water Gulf of Mexico interests (“GOM Interests”) from Exxon Mobil Corporation (“ExxonMobil”) for a total cash consideration of approximately $32.8 million. The GOM Interests cover 5,000 gross acres on Vermilion Block 164 (“VR 164”). We are the operator of these properties. In addition to acquiring the GOM Interests, we entered into a joint venture agreement with ExxonMobil to explore for oil and gas on nine contiguous blocks adjacent to VR 164 in shallow waters on the GOM shelf. We operate the joint venture and commenced drilling on the initial prospect during the quarter ended December 31, 2012. The objective targets at Pendragon well, the initial prospect, were not reached as it encountered mechanical issues and was plugged and abandoned. Subsequently, we began drilling the Merlin well located at Vermilion Block 179; the Merlin well did not encounter any commercial hydrocarbons and was plugged and abandoned. We are currently negotiating an extension of our joint venture with ExxonMobil to further analyze the Pendragon and Merlin wells’ data along with reprocessing the 3D seismic information to determine the future drilling activities on the Vermilion Block.

Revenues and expenses related to the GOM Interests from the closing date of October 17, 2012 are included in our consolidated statements of income. The acquisition of the GOM Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on October 17, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	10,447
Oil and natural gas properties – unevaluated		27,721
Asset retirement obligations		(5,351	)
Cash paid	$	32,817

Dynamic Offshore oil and gas properties interests acquisition

On November 7, 2012, we acquired 100% of the interests (“Dynamic Interests”) held by Dynamic Offshore Resources, LLC (“Dynamic”) on VR 164 for approximately $7.2 million.

Revenues and expenses related to the Dynamic Interests from the closing date of November 7, 2012 are included in our consolidated statements of income. The acquisition of the Dynamic Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on November 7, 2012 (in thousands):

Oil and natural gas properties – evaluated	$	1,753
Oil and natural gas properties – unevaluated		6,571
Asset retirement obligations		(1,091	)
Cash paid	$	7,233

-10-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

McMoRan oil and gas properties interests acquisition

On January 17, 2013, we closed on the acquisition of certain onshore Louisiana interests in the Bayou Carlin field (“Bayou Carlin Interests”) from McMoRan Oil and Gas, LLC (“McMoRan”) for a total cash consideration of $79.3 million. This acquisition was effective as of January 1, 2013. We are the operator of these properties.

Revenues and expenses related to the Bayou Carlin Interests from the closing date of January 17, 2013 are included in our consolidated statements of income. The acquisition of the Bayou Carlin Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on January 17, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	62,499
Oil and natural gas properties – unevaluated		17,184
Asset retirement obligations		(382	)
Cash paid	$	79,301

RoDa oil and gas properties interests acquisition

On March 14, 2013, we acquired 100% of the interests (“RoDa Interests”) held by RoDa Drilling LP (“RoDa”) in the Bayou Carlin field for $32.7 million. This acquisition was effective as of January 1, 2013.

Revenues and expenses related to the RoDa Interests from the closing date of March 14, 2013 are included in our consolidated statements of income. The acquisition of the RoDa Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 14, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	32,777
Asset retirement obligations		(115	)
Cash paid	$	32,662

Tammany oil and gas properties interests acquisition

On June 28, 2013, we closed on the acquisition of certain offshore Louisiana interests in the West Delta field (“West Delta Interests”) from Tammany Energy Ventures, LLC (“Tammany”) for a total cash consideration of $8.3 million. This acquisition was effective as of June 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta Interests are included in our consolidated statements of income from July 1, 2013. The acquisition of West Delta Interests was accounted for under the purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on June 28, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	8,626
Asset retirement obligations		(338	)
Cash paid	$	8,288

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Black Elk Interest

On December 20, 2013, we closed on the acquisition of certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC (“Black Elk”) for a total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013. We are the operator of these properties.

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of income from December 20, 2013. The acquisition of West Delta 30 Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):

Oil and natural gas properties – evaluated	$	15,821
Oil and natural gas properties – unevaluated		6,586
Asset retirement obligations		(10,503	)
Net working capital *		(1,500	)
Cash paid	$	10,404

* Net working capital includes payables.

Walter Oil & Gas Corporation oil and gas properties interests acquisition

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation (“Walter”) for a total cash consideration of approximately $22.8 million. This acquisition is effective January 1, 2014 and we are the operator of these properties.

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of income from March 7, 2014. The acquisition of South Timbalier 54 Interests was accounted for under purchase method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

Oil and natural gas properties – evaluated	$	23,497
Asset retirement obligations		(705	)
Cash paid	$	22,792

The fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.

Apache Joint Venture

On February 1, 2013, we entered into an Exploration Agreement (the “Exploration Agreement”) with Apache to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central GoM Shelf. We have a 25% participation interest in the Exploration Agreement, which expires on February 1, 2018.

The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through June 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014. As of June 30, 2014, our share of costs related to these wells was approximately $28.1 million.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Acquisition of EPL Oil & Gas, Inc. (“EPL”)

We acquired EPL on June 3, 2014. The acquisition has been accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash ("Cash Election"), or 1.669 shares of Energy XXI common stock ("Stock Election") or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock ("Mixed Election" and collectively the ("Merger Consideration")), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the Merger Agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration.

Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash. Following is a summary of the total purchase price of approximately $1,504.3 million, including cash acquired of $206.1 million (in millions other than per share amounts):

Election		EPL Shares		Cash per share		Bermuda Stock		Cash Paid		Bermuda Stock Issued		Bermuda Stock Price on June 3, 2014		Cash Value of Bermuda Stock Issued		Total Purchase Price Paid to EPL
Cash Election			30.6	$	25.92		0.5595	$	792.6		17.1083	$	21.11	$	361.2	$	1,153.8
Mixed Election	*		7.4		25.35		0.5840		186.8		4.3037		21.11		90.8		277.6
Stock Election			1.1		—		1.6690		—		1.9090		21.11		40.3		40.3
Stock Options			0.8		39.00		—		32.6		—				—		32.6
Total			39.9					$	1,012.0		23.3210			$	492.3	$	1,504.3

(*) Includes 4.7 million EPL shares held by EPL stockholders that did not make elections prior to the May 30, 2014 election deadline.

-13-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The following table summarizes the preliminary purchase price allocation for EPL as of June 3, 2014 (in thousands):

	EPL Historical			Fair Value Adjustment			Total
	(Unaudited)
Current assets (excluding deferred income taxes)	$	301,592		$	1,274		$	302,866
Oil and natural gas propertiesa
Evaluated (Including net ARO assets)		1,919,699			112,624			2,032,323
Unevaluated		41,896			859,886			901,782
Other property and equipment		7,787			-			7,787
Other assets		16,227			(9,002	)		7,225
Current liabilities (excluding ARO)		(314,649	)		-			(314,649	)
ARO (current and long-term)		(260,161	)		(13,211	)		(273,372	)
Debt (current and long-term)		(973,440	)		(52,967	)		(1,026,407	)
Deferred income taxesb		(118,359	)		(340,645	)		(459,004	)
Other long-term liabilities		(2,242	)		797			(1,445	)
Total fair value, excluding goodwill		618,350			558,756			1,177,106
Goodwillc		-			327,235			327,235
Less cash acquired								206,075
Total purchase price	$	618,350		$	885,991		$	1,298,266

a. EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy.

b. Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37 percent tax rate, which reflected the 35 percent federal statutory rate and a 2 percent weighted-average of the applicable statutory state tax rates (net of federal benefit).

c. At June 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was unnecessary, and no goodwill impairment was recognized.

EPL’s operating revenues and net income of $60.1 million and $4.2 million for the month ended June 30, 2014 are included in the Consolidated Statement of Income for the year ended June 30, 2014.

In accordance with the acquisition method of accounting, the purchase price from our acquisition of EPL has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed has been recorded as goodwill. Goodwill recorded in connection with the acquisition is not deductible for income tax purposes.

-14-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.

The fair value measurements of the oil and natural gas properties and the asset retirement obligations included in other long-term liabilities were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value measurement of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.

Goodwill primarily resulted from the requirement to recognize deferred taxes on the difference between the fair value and the historical tax basis of the acquired assets.

Costs associated with the EPL Acquisition totaled $13.6 million for the year ended June 30, 2014, which were included in general and administrative expenses in the consolidated statements of income.

The following supplemental unaudited pro forma consolidated financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The unaudited pro forma financial information combines the historical statements of income of Energy XXI and EPL for the years ended June 30, 2014 and 2013.

The historical consolidated financial information has been adjusted to reflect factually supportable items that are directly attributable to the acquisition (in thousands, except per share amounts).



	Years Ended June 30,
	2014			2013
		(Unaudited)
Revenues	$	1,860,200	$		1,927,235
Operating income	277,904			512,869
Net income (loss) from continuing operations	(7,017)			202,904
Net income (loss) available to Energy XXI common stockholders	(18,506)			191,408

Net income (loss) per share available to Energy XXI common stockholders:
Basic	$	(0.16)		$	1.87
Diluted	(0.16)			1.83

The above supplemental unaudited pro forma consolidated financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments to income from continuing operations for the year ended June 30, 2014, were the following:

Exclude $43.3 million of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting.

Increase DD&A expense by $64.2 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

Increase interest expense by $47.8 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for approximately eleven months ended June 3, 2014. Decrease interest expense $13.7 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The most significant pro forma adjustments to income from continuing operations for the year ended June 30, 2013, were the following:

Include net earnings of $57.6 million which represents incremental revenues, lease operating and other direct operating expenses related to EPL’s acquisitions and divestitures from July 1, 2012 to the date of such transactions.

Increase DD&A expense by $116.0 million for the EPL Properties to correspond with EXXI’s full cost method of accounting.

Increase interest expense by $51.9 million to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility for the twelve months ending June 30, 2013. Decrease interest expense $7.0 million to reflect non-cash interest expense associated with the $510 million of EPL’s 8.25% Senior Notes due to the adjustment to fair value of the assumed EPL debt obligations, net of interest expense of $5.4 million to reflect interest on the 8.25% Senior Notes from July 1, 2012.

Sale of Oil and Natural Gas properties interests

On April 1, 2014, we closed on the sale of our interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million, which is subject to customary closing adjustments.

Sale of Oil and Natural Gas properties interests in South Pass 49 field

On June 3, 2014, Energy XXI GOM, LLC, (“EXXI GOM”) our wholly owned indirect subsidiary closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million. As this transaction is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.

Note 4 – Property and Equipment

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

	June 30,
	2014		2013
Oil and natural gas properties
Proved properties	$	8,247,352	$	5,335,737
Less: accumulated depreciation, depletion, amortization and impairment		2,888,451		2,468,783
Proved properties		5,358,901		2,866,954
Unevaluated properties		1,165,701		422,551
Oil and natural gas properties		6,524,602		3,289,505

Other property and equipment		3,173		—
Less: accumulated depreciation		86		—
Other property and equipment		3,087		—
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	6,527,689	$	3,289,505

-16-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The following table summarizes an aging of total costs related to unevaluated properties and wells in progress excluded from the amortization base as of June 30, 2014 (in thousands).

	Net Costs Incurred During the Years Ended June 30,
	2011 and prior		2012		2013		2014			Balance as of June 30, 2014

Unevaluated Properties (acquisition costs)	$	38,289	$	—	$	51,435	$	890,696		$	980,420

Wells in Progress (exploratory costs)		122,724		89,611		120,492		(147,546	)		185,281

	$	161,013	$	89,611	$	171,927	$	743,150		$	1,165,701

The Company’s investment in unevaluated properties primarily relates to the unevaluated oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with these unevaluated properties are transferred to evaluated properties upon the earlier of (i) when a determination is made whether there are any proved reserves related to the properties, or (ii) amortized over a period of time of not more than four years.

Exploratory wells in progress include $185.3 million in costs related to our participation with Freeport-McMoRan, Inc. who operates several prospects in the ultra-deep shelf and onshore area (“ultra-deep trend”) in the Gulf of Mexico. Activities related to certain of these well operations are controlled by the operator and these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.

As of June 30, 2014, the costs associated with our major projects and their status was as follows (in millions):

Project Name	Cost		Status

Davy Jones Facilities	$	22.1	Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well		69.8	Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands.
Blackbeard East		50.8	Plans to complete into the Miocene Sands in late 2015.
Lomond North		42.6	Completion operations in progress to test lower Wilcox and Cretaceous objectives
Total	$	185.3

Note 5 – Long-Term Debt

Long-term debt consists of the following (in thousands):

	June 30,
	2014		2013

Revolving credit facility	$	689,000	$	339,000
9.25% Senior Notes due 2017		750,000		750,000
8.25% Senior Notes due 2018		510,000		—
7.75% Senior Notes due 2019		250,000		250,000
7.5% Senior Notes due 2021		500,000		—
6.875% Senior Notes due 2024		650,000		—
Debt premium, 8.25% Senior Notes due 2018 (1)		40,567		—
Derivative instruments premium financing		21,000		24,681
Total debt		3, 410,567		1,363,681
Less current maturities		14,094		18,838
Total long-term debt	$	3,396,473	$	1,344,843

(1)

Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition at their fair value at June 3, 2014.

-17-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Maturities of long-term debt as of June 30, 2014 are as follows (in thousands):

Year Ending June 30,
2015	$	14,094
2016		6,906
2017		—
2018		1,989,567
2019		250,000
Thereafter		1,150,000
Total	$	3,410,567

Revolving Credit Facility

The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by EGC, in May 2011 and underwent its Eighth Amendment on June 3, 2014 as noted below. This facility, as amended, has lender commitments of $1.7 billion and matures on April 9, 2018, provided that the facility will mature immediately if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base of $1.5 billion, which is based on oil and natural gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions. The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, EGC may not permit the following under First Lien Credit Agreement: (a) EGC’s total leverage ratio to be more than 3.5 to 1.0, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, and (c) EGC’s current ratio (in each case as defined in the First Lien Credit Agreement) to be less than 1.0 to 1.0, as of the end of each fiscal quarter. In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

On September 27, 2013, EGC entered into the Sixth Amendment (the “Sixth Amendment”) to the First Lien Credit Agreement. Under the Sixth Amendment, the borrowing base for EGC was increased from $850 million to $1,087.5 million. Additionally, the Sixth Amendment provided EGC the ability to specify interest periods for LIBOR loans of less than a month in length and made some related adjustments to the definition of LIBOR and other technical corrections.

On April 7, 2014, EGC entered into the Seventh Amendment (the “Seventh Amendment”) to the First Lien Credit Agreement. Under the Seventh Amendment, the borrowing base for EGC was increased from $1,087.5 million to $1,200 million. Additionally, the Seventh Amendment incorporated the 7.50% Senior Notes due 2021 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017 and 7.75% senior unsecured notes due 2019. Also, the Seventh Amendment allowed for the incurrence of an additional $1,000 million of unsecured debt, subject to certain conditions, including that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase.

-18-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

On June 3, 2014, EGC entered into the Eighth Amendment (“the Eighth Amendment”) to the First Lien Credit Agreement. Pursuant to the Eighth Amendment, the borrowing base for EGC was established at $1.5 billion (an increase from $1.2 billion as determined on April 7, 2014) until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. Of this borrowing base amount, EGC established a sub-facility pursuant to the Eighth Amendment for its wholly owned subsidiary, EPL, with a borrowing base of $475 million for such sub-facility. Upon the effectiveness of the Eighth Amendment, EPL immediately borrowed the entire $475 million to refinance the outstanding indebtedness it had under the terms of a credit agreement in existence at the effective time of the acquisition of EPL by EGC. The borrowing base for this sub-facility is subject to redeterminations from time to time generally on the same basis as is the overall borrowing base under the First Lien Credit Agreement. Under the Eighth Amendment, EGC and its subsidiaries, other than EPL and its subsidiaries, have guaranteed and secured the indebtedness of EPL and its subsidiaries, but EPL and its subsidiaries have not commensurately guaranteed the obligations of EGC and its other subsidiaries. However, per the terms of the First Lien Credit Agreement, immediately upon EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes due 2018, EPL and its subsidiaries are required to guarantee and secure the obligations generally of EGC and its subsidiaries and such EPL sub-facility shall terminate and the entire borrowing base amount shall thereupon be available to EGC for credit extensions under the terms of the First Lien Credit Agreement. Most of the terms of the Eighth Amendment generally are in regards to incorporating the concept of EPL as a separate “borrower” for purposes of the First Lien Credit Agreement. Interest accrues and is payable on the EPL sub-facility on the same basis as principal amounts outstanding generally under the First Lien Credit Agreement.

The Eighth Amendment also incorporates a few additional changes, including the incorporation of the concept of EGC’s 6.875% Senior Notes due 2024 and EPL’s 8.25% Senior Notes due 2018 as senior unsecured debt generally permitted under the terms of the First Lien Credit Agreement, so that provisions under the First Lien Credit Agreement for such notes are commensurate with the provisions already existing for EGC’s 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019 and 7.50% senior unsecured notes due 2021. With the Eighth Amendment, EGC retains the ability to further incur $1 billion of permitted unsecured indebtedness, still subject to the condition that the minimum liquidity requirements outlined in the First Lien Credit Agreement would be increased in the amount of 25% of any such new debt incurred until such time as the lenders under the First Lien Credit Agreement otherwise provide or waive such increase. Furthermore, the Eighth Amendment removed the prohibition on the prepayment, redemption or other refinance of EGC’s outstanding 9.25% senior unsecured notes due 2017, 7.75% senior unsecured notes due 2019, 7.50% senior unsecured notes due 2021 and the 6.875% Senior Notes due 2024 and any other permitted unsecured indebtedness incurred by EGC, and instead established certain quantitative liquidity conditions to making any such prepayment, redemption or other refinance of such senior unsecured notes or other permitted unsecured indebtedness. Pursuant to the Eighth Amendment, EGC is permitted to use proceeds from the issuance of further permitted unsecured indebtedness to prepay, redeem or refinance such notes and, upon such action, treat such amount so used as a refinancing of the amount so prepaid redeemed, and restore the availability to incur such amount under the permitted unsecured indebtedness basket.

As of June 30, 2014, EGC was in compliance with the covenants described above and the other financial covenants under the First Lien Credit Agreement with the possible exception of its total leverage ratio. EGC typically completes its audit after the Bermuda parent company completes its audit. Based upon preliminary calculations, EGC determined it may have exceeded the total leverage ratio covenant and therefore EGC sought a temporary increase in the total leverage ratio covenant. EGC’s total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was estimated to be 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this potential violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC believes that it will be able to comply with the current covenants under the First Lien Credit Agreement through June 30, 2015 by taking certain actions within EGC’s control.

As of June 30, 2014, EGC had $689 million in borrowings and $225.7 million in letters of credit issued under our First Lien Credit Agreement.

-19-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

High Yield Facilities

8.25% Senior Notes Due 2018

On June 3, 2014, EGC assumed the 8.25% Senior Notes in EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee (the “8.25% Senior Notes Trustee”), governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the Merger Agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the Consent Time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked.

EGC believes that the fair value of the $510 million of 8.25% Senior Notes outstanding as of June 30, 2014 was $545.7 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

6.875% Senior Notes Due 2024

On May 27, 2014, EGC issued $650 million face value of 6.875%, unsecured senior notes due March 15, 2024 at par (“6.875% Senior Notes”). Presently, the 6.875% Senior Notes are not registered under the Securities Act, however EGC and its guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes.

On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.

The indenture governing the 6.875% Senior Notes will, among other things, limit EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

EGC believes that the fair value of the $650 million of 6.875% Senior Notes outstanding as of June 30, 2014 was $663 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 6.875% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

7.5% Senior Notes Due 2021

On September 26, 2013, EGC issued $500 million face value of 7.5%, unsecured senior notes due December 15, 2021 at par (“7.5% Senior Notes”). Presently, the 7.5% Senior Notes are not registered under the Securities Act, however EGC and its guarantors will agree, pursuant to a registration rights agreement with the initial purchasers of the 7.5% Senior Notes, to file a registration statement with the SEC with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 7.50% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 270 days after the issue date of the 7.5% Senior Notes. In April 2014, we filed Amendment No. 1 to the registration statement for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC, the registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.5% Senior Notes.

On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.5% Senior Notes.

The indenture governing the 7.5% Senior Notes will, among other things, limit EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

EGC believes that the fair value of the $500 million of 7.5% Senior Notes outstanding as of June 30, 2014 was $541.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 7.5% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

9.25% Senior Notes

On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act of 1933, as amended (the “Securities Act”), on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.

The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of June 30, 2014 was $806.6 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 9.25% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

7.75% Senior Notes

On February 25, 2011, EGC issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.

EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.

EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of June 30, 2014 was $269.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

The 7.75% Senior Notes are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries.

Guarantee of Securities Issued by EGC

We are the issuer of each of the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by the Bermuda parent company and each of our existing and future material domestic subsidiaries, with the exception of EPL and its wholly-owned subsidiaries. The Bermuda parent company and its subsidiaries, other than us, have no significant independent assets or operations. We are permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility.”

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase from our hedge counterparties. Substantially all of our hedges are with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of June 30, 2014 and June 30, 2013, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $21 million and $24.7 million, respectively.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Interest Expense

For the years ended June 30, 2014, 2013 and 2012, interest expense consisted of the following (in thousands):

	Year Ended June 30,
	2014			2013		2012

Revolving credit facility	$	13,956		$	11,816	$	9,420
9.25% Senior Notes due 2017		69,375			69,375		69,375
8.25% Senior Notes due 2018		3,507			—		—
7.75% Senior Notes due 2019		19,375			19,375		19,375
7.5% Senior Notes due 2021		28,542			—		—
6.875% Senior Notes due 2024		4,096			—		—
Amortization of debt issue cost - Revolving credit facility		3,076			4,303		4,881
Amortization of debt issue cost – 9.25% Senior Notes due 2017		2,206			2,206		2,206
Amortization of fair value premium – 8.25% Senior Notes due 2018		(841	)		—		—
Amortization of debt issue cost – 7.75% Senior Notes due 2019		388			388		388
Amortization of debt issue cost – 7.50% Senior Notes due 2021		783			—		—
Amortization of debt issue cost – 6.875% Senior Notes due 2022		102			—		—
Derivative instruments premium financing and other		874			897		1,196
Bridge commitment fee		2,481			—		—
Settlement of Lehman Brothers liability		—			—		1,890
	$	147,920		$	108,360	$	108,731

Note 6 – Notes Payable

In May 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $26.0 million and bore interest at an annual rate of 1.556%. The note matured and was repaid on December 26, 2012.

In July 2012, we entered into a note to finance a portion of our insurance premiums. The note was for a total face amount of $3.6 million and bore interest at an annual rate of 1.667%. The note matured and was repaid on May 1, 2013.

In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bore interest at an annual rate of 1.774%. The note matured and was repaid on October 23, 2013.

In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014.

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of June 30, 2014 was $22.0 million.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 7 – Asset Retirement Obligations

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

	Year Ended June 30,
	2014			2013

Balance at beginning of year	$	287,818		$	301,415
Liabilities acquired		284,661			7,277
Liabilities incurred and true up of liabilities settled		41,216			18,486
Liabilities settled		(57,391	)		(41,939	)
Revisions in estimated cash flows		(26,653	)		(28,306	)
Accretion expense		30,183			30,885
Total balance at end of year		559,834			287,818
Less current portion		79,649			29,500
Long-term balance at end of year	$	480,185		$	258,318

Note 8 – Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, for our derivative transactions to reduce the concentration of exposure to any individual counterparty and to reduce exposure to fluctuations in the price of crude oil and natural gas. We use financially settled crude oil and natural gas puts, swaps, zero-cost collars and three-way collars. The Company designates a majority of its derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled.

When the Company discontinues cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes to fair value accumulated in other comprehensive income are recognized immediately into earnings.

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost 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. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). Through June 30, 2011, we utilized West Texas Intermediate (“WTI”), NYMEX based derivatives as the exclusive means of hedging our fixed price commodity risk thereby resulting in HLS/WTI basis exposure. During the quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can more appropriately manage our exposure and price risk. In April 2014 we began including Argus-LLS futures collars in our hedging portfolio to appropriately align and manage our exposure and price risk to market conditions.

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges and expect to carry those hedges through the end of contract term beginning from June 2014 through December 2015. EPL’s oil contracts are primarily swaps and benchmarked to Argus-LLS and Brent.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

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 hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended June 30, 2013, and received $181.3 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of June 30, 2014, all of the monetized amounts remaining in OCI were recognized in income.

During the year ended June 30, 2013, we repositioned certain hedge positions by selling puts on certain existing calendar year 2013 hedge collar contracts and purchasing new put spread contracts. The $2.2 million received from the sale of puts were recorded as deferred hedge revenue and were recognized in income over the life of the underlying hedge contracts through December 31, 2013. As of June 30, 2014, all of the amounts remaining in deferred hedge revenue were recognized in income.

As of June 30, 2014, we had the following net open crude oil derivative positions:

					Weighted Average Contract Price
					Swaps		Collars/Put Spreads
Period	Type of Contract	Index	Volumes (MBbls)		Fixed Price		Sub Floor		Floor		Ceiling

July 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE		766			$	69.00	$	89.00	$	124.99
July 2014 - December 2014	Put Spreads	Oil-Brent-IPE		431				66.43		86.43
July 2014 - December 2014	Collars	Oil-Brent-IPE		368						90.00		108.38
July 2014 - December 2014	Put Spreads	NYMEX-WTI		1,230				70.00		90.00
July 2014 - December 2014	Put	NYMEX-WTI		460						90.00
July 2014 - December 2014	Roll Swap	NYMEX-WTI		2,295	$	1.03
July 2014 - December 2014	Three-Way Collars	NYMEX-WTI		610				70.00		90.00		137.20
July 2014 - December 2014	Swaps	ARGUS-LLS		1,614		92.84
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE		3,650				71.00		91.00		113.75
January 2015 - December 2015	Swaps	Oil-Brent-IPE		548		97.70
January 2015 - December 2015	Collars	ARGUS-LLS		1,825						80.00		123.38
January 2015 - December 2015	Put	NYMEX-WTI		1,813						88.76
January 2015 - December 2015	Roll Swap	NYMEX-WTI		3,180		1.03

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

As of June 30, 2014, we had the following net open natural gas derivative positions:

Weighted Average Contract Price

Swaps

Collars/Put Spreads

Period

Type of Contract

Index

Volumes

(MMBtu)

Fixed Price

Sub Floor

Floor

Ceiling

July 2014 - December 2014

Three-Way Collars

NYMEX-HH

8,187

3.36

4.00

4.60

July 2014 - December 2014

Put Spreads

NYMEX-HH

1,013

3.25

4.00

July 2014 - December 2014

Swaps

NYMEX-HH

920

4.01

January 2015 - December 2015

Swaps

NYMEX-HH

1,570

4.31

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

	Asset Derivative Instruments								Liability Derivative Instruments
	June 30, 2014				June 30, 2013				June 30, 2014				June 30, 2013
	Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value		Balance Sheet Location		Fair Value
Commodity Derivative Instruments designated as hedging instruments:
Derivative financial instruments		Current	$	16,829		Current	$	52,216		Current	$	47,912		Current	$	14,609
		Non-Current		9,595		Non-Current		42,263		Non-Current		10,866		Non-Current		20,337
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		551		Current		1,976		Current		—		Current		1,234
		Non-Current		—		Non-Current		—		Non-Current		—		Non-Current		—
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement				26,975				96,455				58,778				36,180

Derivative financial instruments		Current		(15,955)		Current		(15,803)		Current		(15,955)		Current		(15,803)
		Non-Current		(6,560)		Non-Current		(20,337)		Non-Current		(6,560)		Non-Current		(20,337)
Gross amounts offset in Balance Sheet				(22,515)				(36,140)				(22,515)				(36,140)
Net amounts presented in Balance Sheet		Current		1,425		Current		38,389		Current		31,957		Current		40
		Non-Current		3,035		Non-Current		21,926		Non-Current		4,306		Non-Current		—
			$	4,460			$	60,315			$	36,263			$	40

The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):

	Year Ended June 30,
	2014			2013			2012
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	12,985		$	(13,295	)	$	(438	)
Natural gas sales		(3,619	)		(15,110	)		(28,163	)
Total cash settlements		9,366			(28,405	)		(28,601	)

Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments		6,339			881			(3,479	)

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss		(1,065	)		1,812			(4,542	)
Unrealized mark to market (gain) loss		430			(778	)		760
Total (gain) loss on derivative financial instruments		5,704			1,915			(7,261	)
Total (gain) loss	$	15,070		$	(26,490	)	$	(35,862	)

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The cash flow hedging relationship of our derivative instruments was as follows (in thousands):

Location of (Gain) Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Year Ended June 30, 2014
Commodity Derivative Instruments	$	46,734
Revenues				$	(6,640	)
Loss (gain) on derivative financial instruments							$	6,339
Total	$	46,734		$	(6,640	)	$	6,339

Year Ended June 30, 2013
Commodity Derivative Instruments	$	31,303
Revenues				$	(25,876	)
Loss (gain) on derivative financial instruments							$	881
Total	$	31,303		$	(25,876	)	$	881

Year Ended June 30, 2012
Commodity Derivative Instruments	$	(126,087	)
Revenues				$	(22,372	)
Loss (gain) on derivative financial instruments							$	(3,479	)
Total	$	(126,087	)	$	(22,372	)	$	(3,479	)

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Components of AOCI representing all of the reclassifications out of AOCI to income for the periods presented (in thousands):

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Year ended June 30, 2014
Unrealized gain on derivatives at beginning of year	$	(40,462	)	$	(26,300	)
Unrealized change in fair value during the year		55,344			35,973
Ineffective portion reclassified to earnings during the year		6,339			4,121		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		10,215			6,640		Revenues
Unrealized loss on derivatives at end of year	$	31,436		$	20,434

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Year ended June 30, 2013
Unrealized gain on derivatives at beginning of year	$	(88,620	)	$	(57,603	)
Unrealized change in fair value during the year		7,467			4,853
Ineffective portion reclassified to earnings during the year		881			573		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		39,810			25,877		Revenues
Unrealized gain on derivatives at end of year	$	(40,462	)	$	(26,300	)

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Year ended June 30, 2012
Unrealized loss on derivatives at beginning of year	$	105,360		$	68,484
Unrealized change in fair value during the year		(224,919	)		(146,197	)
Ineffective portion reclassified to earnings during the year		(3,479	)		(2,261	)	Loss on derivative financial instruments
Realized amounts reclassified to earnings during the year		34,418			22,371		Revenues
Unrealized gain on derivatives at end of year	$	(88,620	)	$	(57,603	)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $24.9 million ($16.2 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. 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 these 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. At June 30, 2014, we had no deposits for collateral with our counterparties.

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 9 – Supplemental Cash Flow Information

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

	Year Ended June 30,
	2014		2013		2012

Cash paid for interest	$	132,761	$	99,377	$	103,346

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

	Year Ended June 30,
	2014		2013			2012

Financing of insurance premiums	$	21,967	$	22,524		$	22,211
Derivative instruments premium financing		11,257		18,231			16,259
Additions to property and equipment by recognizing asset retirement obligations		299,225		(9,820	)		(45,998	)
Stock contributions from parent for EPL Acquisition		492,305		-			-

-29-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 10 — Related Party Transactions

During the years ended June 30, 2014, 2013 and 2012, we received (returned) capital contributions of $662.9 million, $(27.7) million and $(2.4) million, respectively, from our Parent.

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc., our indirect parent, bearing a simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $1,910,000, $1,836,000 and $1,099,000 for the years ended June 30, 2014, 2013 and 2012, respectively. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of June 30, 2014.

The Company has no employees; instead it receives management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the years ended June 30, 2014, 2013 and 2012 was approximately $81.4 million, $62.5 million and $77.8 million, respectively, and is included in general and administrative expense.

The Company receives management fees for providing administrative assistance to M21K, LLC, an equity method investee of Bermuda to carry out its operations. For the years ended June 30, 2014 and 2013, the Company received management fees of $3.8 million and $1.7 million, respectively.

The Company reimbursed $3.6 million to its affiliate Energy XXI Insurance Limited for windstorm insurance coverage. The coverage is for period from June 1, 2014 through June 1, 2015. As of June 30, 2014 the unamortized insurance premium of $3.0 million was included in prepaid expenses and other current assets.

Note 11 — 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.

Litigation Related to the Merger

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against EPL, its directors, Energy XXI, Energy XXI Gulf Coast, Inc., a Delaware corporation and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Energy XXI. Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL have allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the merger allegedly provided inadequate consideration to EPL stockholders for their shares of EPL common stock; (ii) the merger agreement contains contractual terms — including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors allegedly received benefits — including (A) an offer for one of EPL’s directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers — that were not equally shared by EPL’s stockholders; (iv) Energy XXI required EPL’s officers and directors to agree to vote their shares of EPL common stock in favor of the merger; and (v) EPL provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire EPL for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by EPL and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the merger, (ii) EPL’s efforts to attract offers from other potential acquirors, (iii) EPL’s evaluation of the merger; (iv) negotiations between EPL and Energy XXI, and (v) the analysis of EPL’s financial advisor. Based on these allegations, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. Neither Energy XXI nor EPL can predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Energy XXI or EPL predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

-30-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Letters of Credit and Performance Bonds. We had $225.7 million in letters of credit and $170.5 million of performance bonds outstanding as of June 30, 2014.

Drilling Rig Commitments. The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2014, we have entered into nine drilling rig commitments:

1) April 10, 2014 to October 27, 2014 at $54,448 per day

2) January 1, 2014 to July 15, 2014 at $107,500 per day

3) October 1, 2013 to September 1, 2014 at $125,000 per day

4) March 10, 2014 to March 9, 2015 at $53,175 per day

5) September 1, 2013 to August 31, 2014 at $140,000 per day

6) February 15, 2014 to August 15, 2014 at $111,380 per day

7) April 11, 2014 to September 15, 2014 at $112,000 per day

8) July 1, 2014 to September 1, 2014 at $107,500 per day.

9) September 1, 2014 to October 1, 2014 at $107,500 per day.

At June 30, 2014, future minimum commitments under these contracts totaled $61.9 million.

Note 12 — Income Taxes

We are a (U.S.) Delaware company and a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI USA, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI (Bermuda) Limited (the “Foreign Parent”) indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon the tax laws and rates of the United States as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the reporting period. We have recorded no income tax related intercompany balances with affiliates.

-31-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The components of our income tax provision are as follows (in thousands):

	Year Ended June 30,
	2014		2013			2012

Current	$	-	$	(2,461	)	$	(53	)
Deferred		52,120		85,889			71,063
Income tax expense (benefit)	$	52,120	$	83,428		$	71,010

The following is a reconciliation of statutory income tax expense to our income tax provision (in thousands):

	Year Ended June 30,
	2014			2013			2012

Income before income taxes	$	149,095		$	266,809		$	386,156
Statutory rate		35	%		35	%		35	%
Income tax expense computed at statutory rate		52,183			93,383			135,155
Reconciling items:
State income taxes, net of federal tax benefit		-			(2,461	)		(53	)
Change in valuation allowance, net		-			(59,853	)		19,334
Tax return-to-provision adjustment to oil and gas properties		-			52,071			-
Revaluation of tax attribute carryovers		-			-			(33,337	)
Cancellation of debt income – GC bond repurchase		-			-			(50,316	)
Other		(63	)		288			227
Income tax expense	$	52,120		$	83,428		$	71,010

-32-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):

	June 30,
	2014			2013
Deferred tax assets – current
Asset retirement obligation	$	44,182		$	-
Other		7,829			-
		52,011			-
Deferred tax assets:
Asset retirement obligations		61,154			100,439
Tax loss carryforwards		380,474			349,663
Deferred state taxes		22,494			22,494
Deferred interest under IRC Sec. 163(j)		-			28,721
Other		24,423			98
Total deferred tax assets		488,545			501,415

Deferred tax liabilities:
Derivative instruments		-			8,602
Oil and gas properties		1,096,531			562,191
Retirement of debt		8,842			9,680
Partnership activity		55,531			52.202
Total deferred tax liabilities		1,160,904			632,675

Valuation allowance		22,494			22,494

Net deferred tax asset (liability)	$	(642,842	)	$	(153,754	)

At June 30, 2014, the U.S. consolidated tax group had a federal tax loss carryforward (“NOLs”) of approximately 1.1 billion and a state income tax loss carryforwards of approximately $743 million including amounts carried into the Company’s U.S. group from the EPL acquisition. The regular U.S. federal income tax NOL will expire in various amounts beginning in 2026 and ending in 2034. As of June 30, 2014, Energy XXI Gulf Coast, Inc. was the primary contributor of the federal and state loss carryforwards to the U.S. consolidated tax group. The Company recorded $459 million in net deferred tax liabilities in conjunction with the EPL acquisition.

-33-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of the Company’s stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 3.0% and 4.5%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. The Company experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014 Based upon the Company’s determination of its annual limitation related to this ownership change, management believes that Section 382 should not otherwise limit the Company’s ability to utilize its federal or state NOLs or other attribute carryforwards during their applicable carryforward periods. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax attribute carryforwards and will reassess realization of these carryforwards periodically.

The U.S. parent filed our initial tax return for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2013. Tax years ended June 30, 2011 through 2014 remain open to examination under the applicable statute of limitations in the U.S. and state tax jurisdictions in which the Company and its affiliates file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On May 13, 2014 , the U.S, Internal Revenue Service (“IRS”) notified the U.S. parent of their intent to examine the U.S. parent’s federal income tax return (Form 1120) for the year ended June 30, 2013. The resolution of unagreed tax issues cannot be predicted with absolute certainty, and differences between what has been recorded and the eventual outcomes may occur.

We have a remaining valuation allowance of $22.5 million related to certain State of Louisiana net operating loss carryovers that we do not currently believe, on a more likely-than-not basis, are realizable due to our current focus on offshore operations. While the U.S. consolidated group historically has paid no (significant) cash taxes, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We are a party to an intercompany agreement whereby we would be responsible for funding consolidated US federal income tax payments. We expect this AMT to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.

Note 13— Concentrations of Credit Risk

Major Customers. We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Shell Trading Company (“Shell”) accounted for approximately 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. J.P. Morgan Ventures Energy Corporation accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell or ExxonMobil curtailed their purchases.

Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.

Derivative Instruments. Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the primary contracts and that the elimination of price risk through our hedging activities reduces volatility in our reported consolidated results of operations, financial position and cash flows from period to period and lowers our overall business risk.

Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.

-34-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

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. The following methods and assumptions were used to estimate the fair values:

The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate 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 LIBOR 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 9 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Form 10-K.

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:

•

Level 1 – quoted prices in active markets for identical assets or liabilities.

•

Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs).

•

Level 3 – unobservable inputs that reflect the Company’s own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

The following table presents the fair value of our Level 2 financial instruments (in thousands):

	Level 2
	As of June 30,
	2014	2013

Assets:
Oil and natural gas derivatives	$26,975	$96,455

Liabilities:
Oil and natural gas derivatives	$58,778	$36,180

-35-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Note 15 — Prepayments and Accrued Liabilities

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

	June 30,
	2014		2013
Prepaid expenses and other current assets
Advances to joint interest partners	$	10,336	$	13,936
Insurance		36,451		28,417
Inventory		7,020		4,094
Royalty deposit		12,262		1,210
Other		3,298		207
Total prepaid expenses and other current assets	$	69,367	$	47,864

Accrued liabilities
Advances from joint interest partners	$	2,667	$	1,348
Interest payable		26,490		5,733
Accrued hedge payable		7,874		2,214
Undistributed oil and gas proceeds		34,473		47,766
Severance taxes payable		8,014		922
Other		5,644		351
Total accrued liabilities	$	85,162	$	58,334

Note 16 – Supplementary Oil and Gas Information – Unaudited

The supplementary data presented reflects information for all of our oil and gas producing activities. Costs incurred for oil and gas property acquisition, exploration and development activities are as follows (in thousands):

	Year Ended June 30,
	2014		2013		2012
Property acquisitions
Proved	$	2,046,879	$	108,825	$	6,401
Unevaluated		924,882		52,339		—
Exploration costs		153,136		168,512		183,397
Development costs		632,262		633,868		327,360

Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. The wells in progress will be transferred into the amortization base once the results of the drilling activities are known.

We excluded from the amortization base the following costs related to unevaluated property costs and major development projects (in thousands):

	Net Costs Incurred During the Years Ended June 30,
	2011 and prior		2012		2013		2014			Balance as of June 30, 2014

Unevaluated Properties (acquisition costs)	$	38,289	$	—	$	51,435	$	890,696		$	980,420

Wells in Progress (exploratory costs)		122,724		89,611		120,492		(147,546	)		185,281

	$	161,013	$	89,611	$	171,927	$	743,150		$	1,165,701

-36-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Estimated Net Quantities of Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our reservoir engineers and audited by NSAI. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:

	Oil			Natural Gas			Total
	(MBbls)			(MMcf)			(MBOE)
Proved reserves at June 30, 2011		77,206			236,316			116,592
Production		(11,172	)		(29,824	)		(16,143	)
Extensions and discoveries		11,444			27,821			16,081
Revisions of previous estimates		9,098			(23,281	)		5,217
Reclassification of proved undeveloped		(1,783	)		(2,042	)		(2,123	)
Proved reserves at June 30, 2012		84,793			208,990			119,624
Production		(10,318	)		(32,354	)		(15,710	)
Extensions and discoveries		40,690			40,714			47,476
Revisions of previous estimates		14,380			7,903			15,697
Reclassification of proved undeveloped		(1,123	)		(1,755	)		(1,416	)
Purchases of reserves		5,225			45,623			12,829
Proved reserves at June 30, 2013		133,647			269,121			178,500
Production		(10,978	)		(32,754	)		(16,437	)
Extensions and discoveries		17,141			19,703			20,424
Revisions of previous estimates		(3,567	)		(29,822	)		(8,537	)
Sales of reserves		(4,159	)		(3,378	)		(4,722	)
Purchases of reserves		53,305			141,986			76,970
Proved reserves at June 30, 2014		185,389			364,856			246,198

Proved developed reserves
June 30, 2011		59,234			134,024			81,572
June 30, 2012		63,308			110,310			81,693
June 30, 2013		80,223			175,623			109,493
June 30, 2014		112,789			222,916			149,942

Proved undeveloped reserves
June 30, 2011		17,972			102,292			35,020
June 30, 2012		21,485			98,680			37,931
June 30, 2013		53,424			93,498			69,007
June 30, 2014		72,600			141,940			96,256

Our proved developed reserve estimates increased by 40.4 MMBOE or 37% to 149.9 MMBOE at June 30, 2014 from 109.5 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition

Additions of 5.4 MMBOE from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from the 4 fields: West Delta 30, Main Pass 61, Main Pass 73 and Grand Isle 16.

-37-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

Offset by:

Downward revision of 2.7 MMBOE, mainly due to lower than forecasted per well throughput at West Delta 73 and sanding issues at South Timbalier 54, offset by positive performance revisions at West Delta 30 and South Pass 49

Divestiture of 4.7 MMBOE, and

Production of 16.4 MMBOE

Our proved undeveloped reserve estimates increased by 27.3 MMBOE or 40% to 96.3 MMBOE at June 30, 2014 from 69.0 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition

Additions of 15.1 MMBOE, primarily additional drilling locations to make up for the lower throughput per well in West Delta 73, replacement locations for South Timbalier 54 and from identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 61.

Offset by

Downward revision of 5.9 MMBOE, primarily due to lease expiration in South Fresh Water Bayou, reallocation of reserves due to new information from the drilling program in Main Pass 61, and change of fluid type due to new information from the drilling program in West Delta 30.

Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

In the fiscal year ended June 30, 2014, we developed approximately 9.5% of our PUD reserves included in our June 30, 2013 reserve report, consisting of 18 gross, 18 net wells at a net cost of approximately $160.9 million. In addition, we also spent $101.7 million in developing PUD reserves that were still in progress at the end of the fiscal year ended June 30, 2014.

We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our report, with the exception of two. They are locations to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.

Standardized Measure of Discounted Future Net Cash Flows

Future cash inflows as of June 30, 2014 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $96.75 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2014). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $103.80 per barrel of oil and $42.10 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $103.80 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $96.75 per barrel (differential of $7.05 per barrel).

For natural gas, the average Henry Hub price used was $4.10 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $4.14 per Mcf after adjusting for energy content, transportation fees, and regional price differentials.

-38-

ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 2014 AND 2013

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2014, 2013 and 2012 are as follows (in thousands):

	June 30,
	2014		2013		2012

Future cash inflows	$	20,162,506	$	15,048,978	$	10,009,119
Less related future
Production costs		5,500,669		3,657,595		2,737,969
Development and abandonment costs		2,959,994		1,838,159		1,304,007
Income taxes		2,546,155		2,591,351		1,377,363
Future net cash flows		9,155,688		6,961,873		4,589,780
Ten percent annual discount for estimated timing of cash flows		3,208,163		2,480,351		1,284,291
Standardized measure of discounted future net cash flows	$	5,947,525	$	4,481,522	$	3,305,489

Changes in Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows (in thousands):

	Year Ended June 30,
	2014			2013			2012

Beginning of year	$	4,481,522		$	3,305,489		$	2,561,393
Revisions of previous estimates
Changes in prices and costs		(196,159	)		(106,002	)		855,382
Changes in quantities		(389,570	)		635,562			153,537
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs		533,133			1,598,548			604,266
Purchases of reserves in place		1,735,957			480,111			—
Accretion of discount		614,964			429,745			333,748
Sales, net of production and gathering and transportation costs		(836,019	)		(842,268	)		(968,956	)
Net change in income taxes		14,134			(676,158	)		(215,873	)
Changes in rate of production		(253,290	)		(456,254	)		(13,438	)
Development costs incurred		247,865			125,925			24,519
Changes in abandonment costs and other		(5,012	)		(13,176	)		(29,089	)
Net change		1,466,003			1,176,033			744,096

End of year	$	5,947,525		$	4,481,522		$	3,305,489

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