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

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8-K - FORM 8-K - Energy XXI Ltd	form8_k.htm

Exhibit 99.1

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2015

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2015

(Unaudited)

C O N T E N T S

	Page

Consolidated Balance Sheets	3

Consolidated Statements of Operations	4

Consolidated Statements of Comprehensive Income (Loss)	5

Consolidated Statements of Cash Flows	6

Notes to Consolidated Financial Statements	7

-2-

ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	March 31,			June 30,
ASSETS	2015			2014
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	553,081		$	9,325
Accounts receivable
Oil and natural gas sales		83,919			167,075
Joint interest billings		16,176			12,898
Other		23,236			4,099
Prepaid expenses and other current assets		36,855			69,367
Deferred income taxes		16,759			52,011
Derivative financial instruments		52,822			1,425
TOTAL CURRENT ASSETS		782,848			316,200
Property and Equipment
Oil and gas properties, net – full cost method of accounting, including $680.0 million and $1,165.7 million of unevaluated properties not being amortized at March 31, 2015 and June 30, 2014, respectively		5,442,041			6,524,602
Other property and equipment, net		2,403			3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		5,444,444			6,527,689
Other Assets
Goodwill		—			329,293
Note receivable from Energy XXI, Inc.		72,904			69,845
Derivative financial instruments		9,767			3,035
Restricted cash		6,024			6,350
Debt issuance costs, net of accumulated amortization		73,438			42,155
Total Other Assets		162,133			450,678
TOTAL ASSETS	$	6,389,425		$	7,294,567
LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	190,384		$	416,576
Accrued liabilities		87,176			85,162
Notes payable		4,949			21,967
Asset retirement obligations		68,392			79,649
Derivative financial instruments		—			31,957
Current maturities of long-term debt		16,461			14,094
TOTAL CURRENT LIABILITIES		367,362			649,405
Long-term debt, less current maturities		4,239,812			3,396,473
Deferred income taxes		243,525			691,779
Asset retirement obligations		462,082			480,185
Derivative financial instruments		71			4,306
Other liabilities		5,332			2,454
TOTAL LIABILITIES		5,318,184			5,224,602
COMMITMENTS AND CONTINGENCIES (NOTE 13)
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		2,002,883			2,092,438
Accumulated deficit		(1,016,764	)		(2,040	)
Accumulated other comprehensive income (loss), net of
income taxes		85,121			(20,434	)
TOTAL STOCKHOLDER’S EQUITY		1,071,241			2,069,965
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	6,389,425		$	7,294,567

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands)

(Unaudited)

	Three Months Ended						Nine Months Ended
	March 31,						March 31,
	2015			2014			2015			2014
Revenues
Oil sales	$	232,274		$	249,955		$	925,430		$	801,414
Natural gas sales		27,672			35,228			95,502			105,177
Total Revenues		259,946			285,183			1,020,932			906,591

Costs and Expenses
Lease operating		107,711			83,624			369,662			263,176
Production taxes		1,537			1,090			6,893			3,677
Gathering and transportation		3,726			5,700			17,685			17,023
Depreciation, depletion and amortization		187,658			99,028			524,705			301,001
Accretion of asset retirement obligations		12,047			6,066			37,664			20,817
Impairment of oil and natural gas properties		870,519			—			870,519			—
Goodwill impairment		—			—			329,293			—
General and administrative expense		35,333			20,232			85,371			56,724
(Gain) loss on derivative financial instruments		1,932			(205	)		(2,237	)		6,958
Total Costs and Expenses		1,220,463			215,535			2,239,555			669,376

Operating Income (Loss)		(960,517	)		69,648			(1,218,623	)		237,215

Other Income (Expense)
Other income, net		688			499			1,642			1,469
Interest expense		(78,852	)		(36,094	)		(199,539	)		(101,535	)
Total Other Expense		(78,164	)		(35,595	)		(197,897	)		(100,066	)

Income (Loss) Before Income Taxes		(1,038,681	)		34,053			(1,416,520	)		137,149

Income Tax Expense (Benefit)		(383,050	)		11,949			(402,546	)		48,043

Net Income (Loss)	$	(655,631	)	$	22,104		$	(1,013,974	)	$	89,106

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)

	Three Months Ended March 31,						Nine Months Ended March 31,
	2015			2014			2015			2014

Net Income (Loss)	$	(655,631	)	$	22,104		$	(1,013,974	)	$	89,106

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		24,399			(4,221	)		276,577			(35,736	)
Effective portion reclassified to earnings during the period		(60,973	)		3,621			(114,186	)		(12,083	)
Total Other Comprehensive Income (Loss)		(36,574	)		(600	)		162,391			(47,819	)
Income Tax (Expense) Benefit		12,801			210			(56,836	)		16,737
Net Other Comprehensive Income (Loss)		(23,773	)		(390	)		105,555			(31,082	)

Comprehensive Income (Loss)	$	(679,404	)	$	21,714		$	(908,419	)	$	58,024

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Nine Months Ended
	March 31,
	2015			2014
Cash Flows from Operating Activities
Net income (loss)	$	(1,013,974	)	$	89,106
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Deferred income tax expense (benefit)		(402,837	)		48,043
Change in derivative financial instruments
Proceeds from sale of derivative instruments		102,354			—
Other – net		748			(549	)
Accretion of asset retirement obligations		37,664			20,817
Depreciation, depletion and amortization		524,705			301,001
Impairment of oil and natural gas properties		870,519			—
Goodwill impairment		329,293			—
Amortization of debt issuance costs and other		8,485			4,698
Changes in operating assets and liabilities:
Accounts receivable		62,832			20,399
Prepaid expenses and other current assets		32,512			27,042
Settlement of asset retirement obligations		(77,177	)		(46,269	)
Accounts payable and other liabilities		(289,087	)		(10,321	)
Net Cash Provided by Operating Activities		186,037			453,967

Cash Flows from Investing Activities
Acquisitions		(301	)		(35,082	)
Capital expenditures		(505,825	)		(572,400	)
Insurance payments received		2,669			—
Transfer from (to) restricted cash		325			(325	)
Proceeds from the sale of properties		7,093			1,748
Other		—			570
Net Cash Used in Investing Activities		(496,039	)		(605,489	)

Cash Flows from Financing Activities
Proceeds from long-term debt		2,586,572			1,703,191
Payments on long-term debt		(1,729,033	)		(1,391,069	)
Advance to Energy XXI, Inc.		(3,059	)		(1,434	)
Contributions from parent		41,759			768
Dividends to parent		(750	)		(150,100	)
Debt issuance costs and other		(41,731	)		(9,834	)
Net Cash Provided by Financing Activities		853,758			151,522

Net Decrease in Cash and Cash Equivalents		543,756			—

Cash and Cash Equivalents, beginning of period		9,325			—

Cash and Cash Equivalents, end of period	$	553,081		$	—

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2015

(UNAUDITED)

Note 1 — Basis of Presentation

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

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

Interim Financial Statements. The accompanying unaudited consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto for the year ended June 30, 2014.

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. Other items subject to estimates and assumptions include fair value of estimates used in accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. 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 differences may be material.

Note 2 – Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest – Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

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Note 3 – Acquisitions and Dispositions

Black Elk Interest

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

Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The following table presents the final 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

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 for total cash consideration of approximately $22.8 million. This acquisition was effective as of January 1, 2014 and we are currently the operator of these properties.

Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The following table presents the final 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

We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. 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) a 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; (3) an inflation factor; and (4) a credit adjusted risk-free interest rate. Fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 14 - Fair Value Measurements.

EPL Oil & Gas, Inc. (“EPL”)

We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method. Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.

In connection with 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 together with the Cash Election and the Stock Election, 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, 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 per share in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, 23.3 million shares of Energy XXI common stock were issued, and we paid approximately $1,012 million in cash.

-8-

The following table summarizes the preliminary purchase price allocation for the EPL Acquisition 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	)		(2,058	)		(316,707	)
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			556,698			1,175,048
Goodwillc,d		—			329,293			329,293
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% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit).

c. See Note 4 - Goodwill for more information regarding goodwill impairment at December 31, 2014.

d. On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million. Accordingly the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill.

In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL 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 was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.

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

-9-

The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase Energy XXI’s equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 - Goodwill for more information regarding the impairment of goodwill at December 31, 2014.

In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the quarter ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $87.3 million and net loss of $50.5 million. For the nine months ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $418.0 million and net loss of $366.0 million.

The following supplemental unaudited pro forma financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on ours and EPL’s historical consolidated statements of income for the three and nine months ended March 31, 2014 (in thousands).

	Three Months Ended March 31, 2014		Nine Months Ended March 31, 2014

Revenues	$	445,744	$	1,419,621
Net income		45,201		151,407

The above supplemental unaudited pro forma 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 for the three and nine months ended March 31, 2014, were the following:

a.	Exclude $5.0 million and $22.0 million, respectively, 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 our full cost method of accounting.

b.	Increase DD&A expense by $17.9 million and $58.5 million, respectively, for the EPL properties to correspond with our full cost method of accounting.

Increase interest expense by $12.8 million and $39.0 million, respectively, to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 (the “6.875% Senior Notes”) and on additional borrowings under our revolving credit facility. Decrease interest expense $3.4 million and $10.0 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million 8.25% senior notes due 2018 (the “8.25% Senior Notes”) assumed in the EPL acquisition.

Disposition of Oil and Natural Gas properties interests

Eugene Island 330 and South Marsh Island 128 Interest

On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of Energy XXI’s 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.

Grand Isle Gathering System

On March 11, 2015, we distributed the Grand Isle gathering system (“Grand Isle Assets”) to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent. The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment. This distribution resulted in a decrease in additional paid-in-capital with no gain or loss recognized.

-10-

The following table summarizes the assets and liabilities distributed (in thousands):


Oil and natural gas properties	$	201,424
Asset retirement obligations		(6,941	)
Deferred income taxes		(67,187	)
Net assets distributed	$	127,296

Note 4 – Goodwill

ASC 350, Intangibles—Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed as of the last day of the fourth quarter each fiscal year.

Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.

At December 31, 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 necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.

In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using a weighted average cost of capital. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

Note 5 – Property and Equipment

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

	March 31,		June 30,
	2015		2014
Oil and gas properties
Proved properties	$	9,044,937	$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment		4,282,945		2,888,451
Proved properties, net		4,761,992		5,358,901
Unevaluated properties		680,049		1,165,701
Oil and gas properties, net		5,442,041		6,524,602

Other property and equipment		3,226		3,173
Less: accumulated depreciation		823		86
Other property and equipment, net		2,403		3,087
Total property and equipment, net of accumulated depreciation, depletion,
amortization and impairment	$	5,444,444	$	6,527,689

At March 31, 2015, the Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL acquisition. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) amortization over a period of time of not more than four years.

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At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties. Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following: 1) the Lomond North project resulted in a successful production test with commercial production commencing in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired. Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the nine months ended March 31, 2015.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. At March 31, 2015, our ceiling test computation resulted in an impairment of our oil and natural gas properties of $870.5 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2015 and 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

The ceiling test computation takes into account the impact of our cash flow hedges at the end of each financial reporting period. Our ceiling test computation would have resulted in an impairment of our oil and natural gas properties of $841.1 million had the effects of the cash flow hedges not been considered in the computation.

Note 6 – Long-Term Debt

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

	March 31,			June 30,
	2015			2014

Revolving Credit Facility	$	150,000			$	689,000
11.0% Senior Secured Second Lien Notes due 2020		1,450,000				—
9.25% Senior Notes due 2017		750,000				750,000
8.25% Senior Notes due 2018		510,000				510,000
7.75% Senior Notes due 2019		250,000				250,000
7.5% Senior Notes due 2021		500,000				500,000
6.875% Senior Notes due 2024		650,000				650,000
Debt premium, 8.25% Senior Notes due 2018 (1)		32,855				40,567
Original issue discount, 11.0% Senior Secured Second Lien Notes due 2020		(53,043	)			—
Derivative instruments premium financing		16,461				21,000
Total debt		4,256,273				3,410,567
Less current maturities		16,461				14,094
Total long-term debt	$	4,239,812			$	3,396,473

_____________________________________

(1)	Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition.

-12-

Maturities of long-term debt as of March 31, 2015 are as follows (in thousands):


Twelve Months Ended March 31,

2016	$	16,461
2017		—
2018		750,000
2019		708,658
2020		1,700,000
Thereafter		1,150,000
		4,325,119
Less: Net original issue discount & debt premium		(68,846	)
Total debt	$	4,256,273

Revolving Credit Facility

On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”) in connection with the issuance of $1.45 billion of senior secured second lien notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020.” Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:

·	reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement;

addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements;

change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of our outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018;

·	elimination, addition, or modification of certain financial covenants;

setting the applicable commitment fee under the First Lien Credit Agreement at 0.50% and providing that outstanding amounts drawn under the First Lien Credit Agreement bear interest at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%;

increase of the threshold requirement for oil and gas properties required to be secured by mortgages to 90% of the value of our (other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but allowing the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) to remain at 85%;

addition of certain further restrictions on the prepayment and repayment of our outstanding note indebtedness, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that we have net liquidity at the time thereof of at least $250 million;

·	modification to the restricted payment covenant to substantially limit our ability to make distributions and dividends to parent entities, provided that a distribution of the Grand Isle Assets and related equipment and other assets is permitted (see Note 12 - Related Party Transactions);

·	qualification on our ability to refinance outstanding indebtedness by requiring that we have pro forma net liquidity of $250 million at the time of such refinancing; and

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modification of the asset disposition covenant to require lender consent for any such disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate; provided, however, that such provision is expressly deemed not to be applicable to certain sales relating to the Grand Isle Assets that are the subject of our current marketing efforts, as long as we meet certain obligations, such as, among others, maintaining the proceeds from such sales in accounts that are subject to the liens of the lenders.

During the quarter ended March 31, 2015, as a result of the reduction in the borrowing capacity under our Revolving Credit Facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.

The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. We are subject to the following financial covenant on a consolidated basis: a minimum current ratio of no less than 1.0 to 1.0. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If the EPL Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.

Under the First Lien Credit Agreement, as amended under the Tenth Amendment, our rights to make distributions to our shareholders (including ultimately to Energy XXI) are substantially reduced. Generally, under the Tenth Amendment, we are only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to us and our subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements.

As of March 31, 2015, we were in compliance with all covenants and had $150.0 million in borrowings and $226.0 million in letters of credit issued under the First Lien Credit Agreement.

11.0% Senior Secured Second Lien Notes Due 2020

On March 12, 2015, we issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI, our ultimate parent company, EXXI USA and certain of EGC’s wholly owned subsidiaries (together with Energy XXI and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”). We received net proceeds of approximately $1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.000%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. As such, the 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15th and September 15th, beginning September 15, 2015. We incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the 11.0% Notes. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the direct offering costs.

The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The 11.0% Notes are secured by second-priority liens on substantially all of EGC and our subsidiary guarantors’ assets and all of EXXI USA’s equity interests in us and its interests in certain assets related to the Grand Isle Assets, in each case to the extent such assets secure our Revolving Credit Facility. In the future, the 11.0% Notes may be guaranteed by certain of our material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.

The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of our future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. EXXI USA also guaranteed the notes on a non-recourse basis limited to the value of equity interests in us that it pledges to secure its guarantee and the Grand Isle Assets in which it grants a security interest in to secure its guarantee. Although the 11.0% Notes are guaranteed by Energy XXI and EXXI USA, Energy XXI and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.

-14-

On or after September 15, 2017, we will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, we may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, we may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. We will be required to offer to purchase all outstanding 11.0% Notes if a ‘‘triggering event’’ occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a ‘‘triggering event’’ will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require us to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.

The 2015 Indenture restricts our ability and the ability of our restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of our assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.

8.25% Senior Notes Due 2018

On June 3, 2014, we assumed the 8.25% Senior Notes in the 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, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL's obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

6.875% Senior Notes Due 2024

On May 27, 2014, we issued the 6.875% Senior Notes which consist of $650 million in aggregate principal amount due March 15, 2024. On November 25, 2014, we filed a registration statement with the Securities and Exchange Commission (“SEC”) for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. On May 1, 2015, we filed Amendment No. 1 to the registration statement and the registration statement was declared effective by the SEC. The exchange offer commenced on May 4, 2015, and we currently expect to complete the exchange offer in June 2015. EGC incurred underwriting and direct offering costs of approximately $11 million which were capitalized and are being amortized over the life of the 6.875% Senior Notes.

On or after March 15, 2019, we will have the right to redeem all or some of the 6.875% Senior Notes at redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, we 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 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, we 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. We are 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 the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of 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, among other things, limits our 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.

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7.5% Senior Notes Due 2021

On September 26, 2013, we issued $500 million face value of 7.5% unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”). In April 2014, we filed Amendment No. 1 to the registration statement with the SEC 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. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.

On or after December 15, 2016, we 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, we 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, we 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. We are required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of 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 limits, among other things, our 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, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.

7.75% Senior Notes Due 2019

On February 25, 2011, we issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). We exchanged the full $250 million aggregate principal amount 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. We incurred underwriting and direct offering costs of $3.1 million which have been capitalized and are being amortized over the life of the notes.

We have the right to redeem the 7.75% Senior Notes under various circumstances and are 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.

9.25% Senior Notes Due 2017

On December 17, 2010, we issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). We exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of the 9.25% Senior Notes registered under 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. We incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.

We have the right to redeem the 9.25% Senior Notes under various circumstances and are 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.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the 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 March 31, 2015 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $16.5 million and $21.0 million, respectively.

-16-

Interest Expense

For the three and nine months ended March 31, 2015 and 2014, interest expense consisted of the following (in thousands):


	Three Months Ended					Six Months Ended
	March 31,					March 31,
	2015			2014		2015			2014

Revolving Credit Facility	$	7,526		$	2,782	$	21,901		$	10,327
11.0% Notes due 2020		8,740			—		8,740			—
9.25% Senior Notes due 2017		17,343			17,343		52,031			52,031
8.25% Senior Notes due 2018		10,518			—		31,556			—
7.75% Senior Notes due 2019		4,843			4,843		14,531			14,531
7.50% Senior Notes due 2021		9,375			9,375		28,125			19,167
6.875% Senior Notes due 2024		11,172			—		33,516			—
Amortization of debt issue cost – Revolving Credit Facility		9,845			571		11,902			2,232
Accretion of original debt issue discount, 11.0% Notes due 2020		418			—		418			—
Amortization of debt issue cost – 11.0% Notes due 2020		327			—		327			—
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552			551		1,655			1,655
Amortization of fair value premium – 8.25% Senior Notes due 2018		(2,608	)		—		(7,712	)		—
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97			97		291			291
Amortization of debt issue cost – 7.50% Senior Notes due 2021		263			260		788			520
Amortization of debt issue cost – 6.875% Senior Notes due 2024		282			—		845			—
Derivative instruments financing and other		159			272		625			781
	$	78,852		$	36,094	$	199,539		$	101,535

Note 7 – Notes Payable

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 March 31, 2015 was $4.0 million.

On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015. The balance outstanding as of March 31, 2015 was $0.9 million.

Note 8 – Asset Retirement Obligations

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


Balance at June 30, 2014	$	559,834
Liabilities incurred and true-up to liabilities settled		20,411
Liabilities settled		(77,177	)
Liabilities sold and transferred		(10,258	)
Accretion expense		37,664
Total balance at March 31, 2015		530,474
Less current portion		68,392
Long-term balance at March 31, 2015	$	462,082

Note 9 – Derivative Financial Instruments

We enter into hedging transactions with a diversified group of investment-grade rated counterparties, primarily financial institutions, 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, put spreads, swaps, zero-cost collars and three-way collars. We designate a majority of our 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.

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When we discontinue cash flow hedge accounting because it is no longer probable that an anticipated transaction will occur in the originally expected period, changes in fair value in accumulated other comprehensive income (“AOCI”) are recognized immediately into earnings.

Monetized amounts are recorded in stockholder's equity as part of AOCI and are recognized in income over the contract life of the underlying hedge contracts.

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. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. 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”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.

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

Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning in June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts keeping one natural gas contract intact.

During fiscal year 2015, we monetized certain of our hedge positions and received cash proceeds of approximately $102.4 million and recorded approximately $99.5 million in AOCI as follows (in thousands):


Quarter Ended	Cash Proceeds		Unamortized Premium			Positive Change in Fair Value		Realized Ineffectiveness Gain on Monetization			Amount Recorded in AOCI on Monetization
September 30, 2014	$	3,364	$	-		$	-	$	-		$	3,364
December 31, 2014		25,873		(4,717	)		2,944		-			24,100
March 31, 2015		73,117		-			-		(1,128	)		71,989
	$	102,354	$	(4,717	)	$	2,944	$	(1,128	)	$	99,453

During the three and nine months ended March 31, 2015, we recognized the following monetized amounts in revenues (in thousands):


Quarter Ended	Three Months		Nine Months
March 31, 2015	$	20,223	$	21,422
March 31, 2014	$	-	$	10,300

As of March 31, 2015, we had approximately $78.0 million of monetized amounts remaining in AOCI which will be recognized in income as follows (in thousands):


Quarter Ended	Amount
June 30, 2015	$	27,495
September 30, 2015		25,419
December 31, 2015		25,117
	$	78,031

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As of March 31, 2015, we had the following net open crude oil derivative positions:


							Weighted Average Contract Price
	Type of		Volumes			Collars/Put
Remaining Contract Term	Contract	Index	(MBbls)			Sub Floor			Floor			Ceiling

April 2015 - December 2015	Three-Way Collars	ARGUS-LLS		5,500			$	32.50		$	45.00		$	75.00
April 2015 - December 2015	Collars	ARGUS-LLS		1,375							80.00			123.38
April 2015 - December 2015	Collars	NYMEX-WTI		413							75.00			85.00
April 2015 - December 2015	Bought Put	NYMEX-WTI		1,053							90.00
April 2015 - December 2015	Sold Put	NYMEX-WTI		(1,053	)						90.00
January 2016 - December 2016	Collars	NYMEX-WTI		5,124							51.43			74.70

As of March 31, 2015, we had the following net open natural gas derivative position:

	Type of		Volumes	Swaps
Remaining Contract Term	Contract	Index	(MMBtu)	Fixed Price

April 2015 - December 2015	Swaps	NYMEX-HH	1,183	$	4.31

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

	Asset Derivative Instruments							Liability Derivative Instruments
	March 31, 2015			June 30, 2014				March 31, 2015				June 30, 2014
	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	$	104,660		Current	$	16,829		Current	$	51,838		Current	$	47,912
	Non-Current		20,860		Non-Current		9,595		Non-Current		11,164		Non-Current		10,866
Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments	Current		—		Current		551		Current		—		Current		—
	Non-Current		—		Non-Current		—		Non-Current		—		Non-Current		—
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement			125,520				26,975				63,002				58,778

Derivative financial instruments	Current		(51,838)		Current		(15,955)		Current		(51,838)		Current		(15,955)
	Non-Current		(11,093)		Non-Current		(6,560)		Non-Current		(11,093)		Non-Current		(6,560)
Gross amounts offset in Balance Sheets			(62,931)				(22,515)				(62,931)				(22,515)
Net amounts presented in Balance Sheets	Current		52,822		Current		1,425		Current				Current		31,957
	Non-Current		9,767		Non-Current		3,035		Non-Current		—		Non-Current		4,306
		$	62,589			$	4,460			$	71			$	36,263

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

	Three Months Ended March 31,						Nine Months Ended March 31,
	2015			2014			2015			2014
Location of (Gain) Loss in Statement of Operations
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	(54,915	)	$	4,686		$	(98,208	)	$	7,819
Natural gas sales		(659	)		2,334			(2,128	)		(3,893	)
Total cash settlements		(55,574	)		7,020			(100,336	)		3,926

Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		3,060			(268	)		(1,631	)		7,407

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		(1,128	)		70			(785	)		(1,150	)
Unrealized mark to market (gain) loss		—			(7	)		179			701
Total (gain) loss on derivative financial instruments		1,932			(205	)		(2,237	)		6,958
Total (gain) loss	$	(53,642	)	$	6,815		$	(102,573	)	$	10,884

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

	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,		Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss,			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss
	net of tax		net of tax			(Ineffective
Location of (Gain) Loss	(Effective Portion)		(Effective Portion)			Portion)
Three Months Ended March 31, 2015
Commodity Derivative Instruments	$	23,773	$	—		$	—
Revenues		—		(39,632	)		—
Gain on derivative financial instruments		—		—			3,060
Total (gain) loss	$	23,772	$	(39,632	)	$	3,060

Three Months Ended March 31, 2014
Commodity Derivative Instruments	$	390	$	—		$	—
Revenues		—		2,354			—
Loss on derivative financial instruments		—		—			(268	)
Total (gain) loss	$	390	$	2, 354		$	(268	)

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	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss,			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss,			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss
	net of tax			net of tax			(Ineffective
Location of (Gain) Loss	(Effective Portion)			(Effective Portion)			Portion)
Nine Months Ended March 31, 2015
Commodity Derivative Instruments	$	(105,555	)	$	—		$	—
Revenues		—			(74,221	)		—
Gain on derivative financial instruments		—			—			(1,631	)
Total (gain)	$	(105,555	)	$	(74,221	)	$	(1,631	)

Nine Months Ended March 31, 2014
Commodity Derivative Instruments	$	31,082		$	—		$	—
Revenues		—			(7,854	)		—
Loss on derivative financial instruments		—			—			7,407
Total (gain) loss	$	31,082		$	(7,854	)	$	7,407

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

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Three months ended March 31, 2015
Unrealized gain on derivatives at beginning of period	$	(167,530	)	$	(108,894	)
Unrealized change in fair value		(27,459	)		(17,848	)
Ineffective portion reclassified to earnings during the period		3,060			1,989		Gain on derivative financial instruments
Realized amounts reclassified to earnings during the period		60,973			39,632		Revenues
Unrealized gain on derivatives at the end of period	$	(130,956	)	$	(85,121	)

Three months ended March 31, 2014
Unrealized loss on derivatives at beginning of period	$	6,758		$	4,392
Unrealized change in fair value		3,953			2,570
Ineffective portion reclassified to earnings during the period		268			174		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		(3,622	)		(2,354	)	Revenues
Unrealized loss on derivatives at end of period	$	7,357		$	4,782

-21-

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Nine months ended March 31, 2015
Unrealized loss on derivatives at beginning of period	$	31,436		$	20,434
Unrealized change in fair value		(274,947	)		(178,715	)
Ineffective portion reclassified to earnings during the period		(1,631	)		(1,061	)	Gain on derivative financial instruments
Realized amounts reclassified to earnings during the period		114,186			74,221		Revenues
Unrealized gain on derivatives at the end of period	$	(130,956	)	$	(85,121	)

Nine months ended March 31, 2014
Unrealized gain on derivatives at beginning of period	$	(40,461	)	$	(26,300	)
Unrealized change in fair value		28,328			18,414
Ineffective portion reclassified to earnings during the period		7,407			4,815		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		12,083			7,853		Revenues
Unrealized loss on derivatives at end of period	$	7,357		$	4,782

The amount expected to be reclassified from AOCI to net income in the next 12 months is a gain of $120.3 million ($78.2 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 our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At March 31, 2015, we had no deposits for collateral with our counterparties.

Note 10 – 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, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI 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 U.S.; accordingly, income taxes have been provided based upon the tax laws and rates of the U.S. 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 financial reporting 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 year-to-date reporting period. We have recorded no income tax related intercompany balances with affiliates. However, during the second quarter of fiscal year 2015, we recorded a goodwill impairment charge of $329 million (see Note 4 - Goodwill). In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes.

We have a remaining valuation allowance of $23.8 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. However, the transfer of the Grand Isle Assets generated current year Louisiana-only taxable income this period; thus we have released $3.0 million of previously recorded Louisiana valuation allowance as a discrete item this quarter. 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 U.S. 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.

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Note 11 – Supplemental Cash Flow Information

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


	Nine Months Ended March 31,
	2015		2014

Cash paid for interest	$	164,383	$	63,854
Cash paid for income taxes		—		3,362

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


	Nine Months Ended March 31,
	2015		2014

Financing of insurance premiums	$	931	$	2,355
Derivative instruments premium financing		12,025		3,493
Additions to property and equipment by recognizing asset retirement obligations		20,411		38,513
Net distribution of Grand Isle Assets to parent (1)		127,296		—

(1) See Note 3- Acquisitions and Dispositions

Note 12 — Related Party Transactions

On March 11, 2015, we distributed the Grand Isle Assets to our Parent pursuant to an assignment and bill of sale between certain of our subsidiaries and our Parent. The Grand Isle Assets include a liquids gathering system consisting of a system of pipelines, storage tanks, processing facilities, salt water disposal facilities and related facilities and equipment. This distribution resulted in a decrease in additional paid-in-capital of $127.3 million, reflecting the net book value of the assets distributed, net of related deferred tax liabilities.

Also on March 11, 2015, we entered into an agreement with our Parent providing for the transportation of certain of our oil production on the Grand Isle gathering system. For the quarter ended March 31, 2015, we incurred charges totaling $2.0 million related to transportation services under this agreement.

During the nine months ended March 31, 2015 and 2014, we paid dividends of $0.8 million and $150.1 million, respectively, to our Parent. During the nine months ended March 31, 2015 and 2014, our Parent contributed approximately $41.8 million and $0.8 million, respectively, to us.

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 $0.5 million for the three months ended March 31, 2015 and 2014. Interest on the note receivable amounted to approximately $1.4 million for the nine months ended March 31, 2015 and 2014. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of March 31, 2015.

During the nine months ended March 31, 2015, we reimbursed $3.0 million to our affiliate Energy XXI Insurance Limited for windstorm insurance coverage. The coverage is for period from June 1, 2014 through June 1, 2015.

We have no employees; instead we receive management services from Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. 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 three months and nine months ended March 31, 2015 was approximately $34.8 million and $66.9 million, respectively, and the cost of these services for the three months and nine months ended March 31, 2014 was approximately $19.7 million and $56.1 million, respectively. These costs are included in general and administrative expense.

Prior to M21K acquiring the interests in certain oil and natural gas fields owned by LLOG Exploration Offshore, L.L.C. ( the “LLOG Exploration acquisition”), we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties were purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three and nine months ended March 31, 2015, we received management fees of $0.7 million and $2.1 million, respectively. For the three and nine months ended March 31, 2014, we received management fees of $1.0 million and $2.8 million, respectively.

On April 1, 2014, EXXI GOM sold its interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, it sold 100% of its interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Quarterly Report.

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Note 13 — Commitments and Contingencies

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

Litigation Related to 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 the Company, EPL, its directors, Energy XXI, 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 alleged 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 provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) EPL’s directors allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the merger agreement rescinded and also sought damages and attorneys’ fees.

On January 16, 2015, plaintiffs filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.

Bureau of Ocean Energy Management ("BOEM") and Other Bonding Related to Oil and Gas Property Abandonment

As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”), we maintain approximately $7.5 million in lease and/or area bonds issued to the BOEM that assures our commitment to comply with the terms and conditions of those leases. We also maintain approximately $162.5 million in bonds issued to predecessor third party assignors of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $1.0 billion, which amount is currently being negotiated by us. We are currently evaluating the impact of the BOEM letters on our future consolidated financial position, results of operations and cash flow. We intend to continue to work with the BOEM staff to resolve this matter, and we have already undertaken a number of initiatives to mitigate our potential liability resulting from the waiver disqualification and to limit the amount of required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date as well as counting our existing bonds with third parties and certain letters of credit against the BOEM bonding request. The costs of satisfying these supplemental bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit or other collateral to support the issuance of any required bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit Facility, which would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. If we are unable to obtain the additional required bonds or assurances requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

Note 14 — Fair Value of Financial Instruments

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

·	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 our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability.

-24-

For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, and 6.875% Senior Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, 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.

During the nine months ended March 31, 2015, we did not have any transfers from or to Level 3. The following table sets forth our Level 2 financial assets and liabilities that are accounted for at fair value on a recurring basis (in thousands):

	Level 2
	As of March 31,			As of June 30,
	2015			2014
Assets:
Oil and natural gas derivatives		$	125,520		$	26,975

Liabilities:
Oil and natural gas derivatives		$	63,002		$	58,778

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

	March 31, 2015				June 30, 2014
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Revolving credit facility	$	150,000	$	150,000	$	689,000	$	689,000
11.0% Senior Notes due 2020		1,396,957		1,384,750		—		—
8.25% Senior Notes due 2018		542,855		379,761		550,567		545,700
6.875% Senior Notes due 2024		650,000		234,000		650,000		663,000
7.5% Senior Notes due 2021		500,000		192,415		500,000		541,250
7.75% Senior Notes due 2019		250,000		108,233		250,000		269,480
9.25% Senior Notes due 2017		750,000		518,295		750,000		806,630
	$	4,239,812	$	2,967,454	$	3,389,567	$	3,515,060

The 11.0% Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings. Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at March 31, 2015 are not material.

-25-

Note 15 — Prepayments and Accrued Liabilities

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

	March 31,		June 30,
	2015		2014

Prepaid expenses and other current assets
Advances to joint interest partners	$	8,219	$	10,336
Insurance		6,461		36,451
Inventory		7,849		7,020
Royalty deposit		10,490		12,262
Other		3,836		3,298
Total prepaid expenses and other current assets	$	36,855	$	69,367

Accrued liabilities
Advances from joint interest partners	$	3,087	$	2,667
Interest payable		52,713		26,490
Accrued hedge payable		1,145		7,874
Undistributed oil and gas proceeds		20,145		34,473
Severance taxes payable		892		8,014
Other		9,194		5,644
Total accrued liabilities	$	87,176	$	85,162

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - May 21, 2015

Attached files

Energy XXI Ltd Reports