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

DECEMBER 31, 2014

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2014

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

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED BALANCE SHEETS

(In Thousands, except share information)

	December 31,			June 30,
ASSETS	2014			2014
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	9,325
Accounts receivable
Oil and natural gas sales		102,882			167,075
Joint interest billings		19,098			12,898
Other		28,971			4,099
Prepaid expenses and other current assets		46,204			69,367
Deferred income taxes		11,235			52,011
Derivative financial instruments		150,026			1,425
TOTAL CURRENT ASSETS		358,416			316,200
Property and Equipment
Oil and gas properties, net – full cost method of accounting, including $807.8 million and $1,165.7 million of unevaluated properties not being amortized at December 31, 2014 and June 30, 2014, respectively		6,642,565			6,524,602
Other property and equipment, net		2,627			3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		6,645,192			6,527,689
Other Assets
Goodwill		—			329,293
Note receivable from Energy XXI, Inc.		70,808			69,845
Derivative financial instruments		8,377			3,035
Restricted cash		6,024			6,350
Debt issuance costs, net of accumulated amortization		40,037			42,155
Total Other Assets		125,246			450,678
TOTAL ASSETS	$	7,128,854		$	7,294,567
LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	313,137		$	416,576
Accrued liabilities		68,837			85,162
Notes payable		12,175			21,967
Asset retirement obligations		79,573			79,649
Derivative financial instruments		—			31,957
Current maturities of long-term debt		20,752			14,094
TOTAL CURRENT LIABILITIES		494,474			649,405
Long-term debt, less current maturities		3,636,771			3,396,473
Deferred income taxes		701,436			691,779
Asset retirement obligations		470,523			480,185
Derivative financial instruments	—				4,306
Other liabilities		5,332			2,454
TOTAL LIABILITIES		5,308,536			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		2,072,556			2,092,438
Accumulated deficit		(361,133	)		(2,040	)
Accumulated other comprehensive income (loss), net of
income taxes		108,894			(20,434	)
TOTAL STOCKHOLDER’S EQUITY		1,820,318			2,069,965
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	7,128,854		$	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						Six Months Ended
	December 31,						December 31,
	2014			2013			2014			2013
Revenues
Oil sales	$	324,655		$	262,230		$	693,156		$	551,459
Natural gas sales		33,100			34,586			67,830			69,949
Total Revenues		357,755			296,816			760,986			621,408

Costs and Expenses
Lease operating		119,366			93,789			261,951			179,552
Production taxes		2,263			1,189			5,356			2,587
Gathering and transportation		4,771			5,978			13,959			11,323
Depreciation, depletion and amortization		176,519			102,511			337,047			201,973
Accretion of asset retirement obligations		12,798			7,425			25,617			14,751
Goodwill impairment		329,293			—			329,293			—
General and administrative expense		35,045			15,163			50,038			36,492
(Gain) loss on derivative financial instruments		(886	)		5,722			(4,169	)		7,163
Total Costs and Expenses		679,169			231,777			1,019,092			453,841

Operating Income (Loss)		(321,414	)		65,039			(258,106	)		167,567

Other Income (Expense)
Other income, net		490			487			954			970
Interest expense		(60,637	)		(35,837	)		(120,687	)		(65,441	)
Total Other Expense		(60,147	)		(35,350	)		(119,733	)		(64,471	)

Income (Loss) Before Income Taxes		(381,561	)		29,689			(377,839	)		103,096

Income Tax Expense (Benefit)		(21,134	)		10,401			(19,496	)		36,094

Net Income (Loss)	$	(360,427	)	$	19,288		$	(358,343	)	$	67,002

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 December 31,						Six Months Ended December 31,
	2014			2013			2014			2013

Net Income (Loss)	$	(360,427	)	$	19,288		$	(358,343	)	$	67,002

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		195,263			(8,858	)		252,179			(31,515	)
Effective portion reclassified to earnings during the period		(51,225	)		(8,357	)		(53,214	)		(15,704	)
Total Other Comprehensive Income (Loss)		144,038			(17,215	)		198,965			(47,219	)
Income Tax (Expense) Benefit		(50,413	)		6,025			(69,637	)		16,527
Net Other Comprehensive Income (Loss)		93,625			(11,190	)		129,328			(30,692	)

Comprehensive Income (Loss)	$	(266,802	)	$	(8,098	)	$	(229,015	)	$	36,310

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Six Months Ended
	December 31,
	2014			2013
Cash Flows from Operating Activities
Net income (loss)	$	(358,343	)	$	67,002
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Deferred income tax expense (benefit)		(19,496	)		36,094
Change in derivative financial instruments
Proceeds from sale of derivative instruments		29,236			—
Other – net		(1,307	)		(364	)
Accretion of asset retirement obligations		25,617			14,751
Depreciation, depletion and amortization		337,047			201,973
Goodwill impairment		329,293			—
Amortization of debt issuance costs and other		(683	)		3,250
Changes in operating assets and liabilities:
Accounts receivables		34,237			16,870
Prepaid expenses and other current assets		23,163			(5,111	)
Settlement of asset retirement obligations		(53,960	)		(34,038	)
Accounts payable and other liabilities		(146,920	)		(36,171	)
Net Cash Provided by Operating Activities		197,884			264,256

Cash Flows from Investing Activities
Acquisitions		(287	)		(12,564	)
Capital expenditures		(442,606	)		(386,979	)
Transfer from (to) restricted cash		326			(746	)
Proceeds from the sale of properties		6,947			1,748
Net Cash Used in Investing Activities		(435,620	)		(398,541	)

Cash Flows from Financing Activities
Dividends to parent		(750	)		(150,100	)
Proceeds from long-term debt		1,011,948			1,428,117
Payments on long-term debt		(759,639	)		(1,127,673	)
Advance to Energy XXI, Inc.		(963	)		(963	)
Returns to parent		(19,882	)		(5,158	)
Debt issuance costs and other		(2,303	)		(9,938	)
Net Cash Provided by Financing Activities		228,411			134,285

Net Decrease in Cash and Cash Equivalents		(9,325	)		—

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

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

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2014

(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. (its “Parent”). 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 Parent. EGC (together, with its wholly owned subsidiaries, the “Company”), is an independent oil and natural gas company, headquartered in Houston, Texas. We are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and offshore in the Gulf of Mexico.

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. The standard is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.

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.

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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 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 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; and (3) 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.

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In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election”) and collectively the (“Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, 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, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash.

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 Gulf of Mexico (“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.

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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.

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 our 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, that 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. EPL’s operating revenues and net loss of $156.6 million and $326.2 million for the quarter ended December 31, 2014 are included in the Consolidated Statement of Operations for the quarter ended December 31, 2014. EPL’s operating revenues and net loss of $330.7 million and $315.5 million for the six months ended December 31, 2014 are included in the Consolidated Statement of Operations for the six months ended December 31, 2014.

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 six months ended December 31, 2013 (in thousands).

		Three Months Ended December 31, 2013			Six Months Ended December 31, 2013
Revenues	$	447,055		$	973,877
Net income (loss)		(4,179	)		35,410

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 six months ended December 31, 2013, were the following:

Exclude $13.6 million and $17.0 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.

Increase DD&A expense by $24.2 million and $39.8 million, respectively, for the EPL properties to correspond with our full cost method of accounting.

Increase interest expense by $13.1 million and $26.2 million, respectively, to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under our revolving credit facility. Decrease interest expense $3.3 million and $6.6 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of EPL’s 8.25% Senior Notes assumed in the EPL acquisition.

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Sales of Oil and Natural Gas properties interests

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.

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

Note 4 – 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 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.

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Note 5 – Property and Equipment

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

		December 31,	June 30,
		2014	2014
Oil and gas properties
Proved properties	$	9,059,934	$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment		3,225,183		2,888,451
Proved properties, net		5,834,751		5,358,901
Unevaluated properties		807,814		1,165,701
Oil and gas properties, net		6,642,565		6,524,602

Other property and equipment		3,231		3,173
Less: accumulated depreciation		604		86
Other property and equipment, net		2,627		3,087
Total property and equipment, net of accumulated depreciation, depletion,
amortization and impairment	$	6,645,192	$	6,527,689

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), exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. 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.

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 expected to commence 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 quarter ended December 31, 2014.

Note 6 – Long-Term Debt

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

	December 31,		June 30,
	2014		2014

Revolving Credit Facility	$	941,309	$	689,000
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)		35,462		40,567
Derivative instruments premium financing		20,752		21,000
Total debt		3,657,523		3,410,567
Less current maturities		20,752		14,094
Total long-term debt	$	3,636,771	$	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 December 31, 2014 are as follows (in thousands):


Twelve Months Ended December 31,

2015	$	20,752
2016		—
2017		750,000
2018		1,486,771
2019		250,000
Thereafter		1,150,000
Total	$	3,657,523

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”) in May 2011 and it underwent its Ninth Amendment on September 5, 2014. This facility, as amended, has a borrowing base of $1,500 million and lender commitments of $1,700 million and matures on April 9, 2018, provided that the facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The Revolving Credit Facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, we are allowed to pay Energy XXI a limited amount of distributions, subject to certain terms and conditions.

The First Lien Credit Agreement, as amended, requires us to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) our interest coverage ratio to be less than 3.0 to 1.0, (c) our current ratio to be less than 1.0 to 1.0, and (d) our secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in the First Lien Credit Agreement). In addition, we are subject to various other covenants including, but not limited to, those limiting our ability to declare and pay dividends or other payments, our ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

As of December 31, 2014, we were in compliance with all covenants and had $941.3 million in borrowings and $226.3 million in letters of credit issued under the First Lien Credit Agreement. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with certain covenants under this agreement in certain future periods. We are focused on reducing our leverage and are pursuing arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of required capital commitments. We are also evaluating various alternatives with respect to the First Lien Credit Agreement, including other sources of financing, although any such alternative sources of financing likely would be at higher cost than our current Revolving Credit Facility. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. Certain payment defaults or an acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

-13-

8.25% Senior Notes Due 2018

On June 3, 2014, we assumed the 8.25% senior notes due 2018 (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 $650 million face value of 6.875% unsecured senior notes due March 15, 2024 at par (the “6.875% Senior Notes”). Presently, the 6.875% Senior Notes are not registered under the Securities Act of 1933, as amended (the “Securities Act”). However, we and our guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes. On November 25, 2014, we filed a registration statement with the 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. The registration statement was not yet declared effective by the SEC as of January 30, 2015. we incurred underwriting and direct offering costs of approximately $11 million which have been 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 specified 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.

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.

-14-

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”). It 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”). It exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act 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 December 31, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $20.8 million and $21.0 million, respectively.

-15-

Interest Expense

For the three and six months ended December 31, 2014 and 2013, interest expense consisted of the following (in thousands):

	Three Months Ended		Six Months Ended
	December 31,		December 31,
	2014	2013	2014	2013

Revolving Credit Facility	$ 7,482	$ 2,326	$ 14,375	$ 7,545
9.25% Senior Notes due 2017	17,344	17,344	34,688	34,688
8.25% Senior Notes due 2018	10,519	—	21,038	—
7.75% Senior Notes due 2019	4,844	4,844	9,688	9,688
7.50% Senior Notes due 2021	9,375	9,271	18,750	9,792
6.875% Senior Notes due 2024	11,172	—	22,344	—
Amortization of debt issue cost – Revolving Credit Facility	1,080	855	2,057	1,661
Amortization of debt issue cost – 9.25% Senior Notes due 2017	551	552	1,103	1,104
Amortization of fair value premium – 8.25% Senior Notes due 2018	(2,570)	—	(5,104)	—
Amortization of debt issue cost – 7.75% Senior Notes due 2019	97	97	194	194
Amortization of debt issue cost – 7.50% Senior Notes due 2021	262	260	525	260
Amortization of debt issue cost – 6.875% Senior Notes due 2024	282	—	563	—
Derivative instruments financing and other	199	288	466	509
	$ 60,637	$ 35,837	$ 120,687	$ 65,441

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 December 31, 2014 was $10.0 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 December 31, 2014 was $2.2 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		21,912
Liabilities settled		(53,960	)
Liabilities sold		(3,307	)
Accretion expense		25,617
Total balance at December 31, 2014		550,096
Less current portion		79,573
Long-term balance at December 31, 2014	$	470,523

-16-

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.

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.

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 the quarters ended September 30, 2014 and December 31, 2014, we monetized certain of our hedge positions and received proceeds of $3.4 million and $26 million, respectively. These monetized amounts received along with $4.8 million of financed premiums payable related to the monetized contracts and a $2.9 million positive change in fair value of the monetized EPL Brent contracts have been recorded in stockholders’ equity as part of AOCI and will be recognized in income over the contract life of the underlying hedge contracts through December 31, 2015. As of December 31, 2014, we had $26.3 million of monetized amounts remaining in AOCI of which $7.6 million, $7.9 million, $5.6 million and $5.2 million will be recognized in income during the quarters ending March 31, 2015, June 30, 2015, September 30, 2015, and December 31, 2015, respectively.

During the three months ended December 31, 2014, we recognized approximately $1.2 million of monetized amounts in net income and during the three and six months ended December 31, 2013, we recognized approximately $5.1 million and $10.3 million, respectively, of monetized amounts in net income.

During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million; further, we repositioned our calendar 2015 hedging portfolio by entering into Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices.

-17-

As of December 31, 2014, we had the following net open crude oil derivative positions:

Weighted Average Contract Price

Type of

Volumes

Collars/Put Spreads

Remaining Contract Term

Contract

Index

(MBbls)

Sub Floor

Floor

Ceiling

January 2015 - December 2015

Three-Way Collars

Oil-Brent-IPE

3,650

$ 71.00

$ 91.00

$ 113.75

January 2015 - December 2015

Collars

ARGUS-LLS

1,825

80.00

123.38

January 2015 - December 2015

Puts

NYMEX-WTI

405

86.11

January 2015 - December 2015

Put Spreads

ARGUS-LLS

2,555

70.00

80.00

January 2015 - December 2015

Collars

NYMEX-WTI

548

75.00

85.00

January 2015 - December 2015

Bought Put

NYMEX-WTI

1,593

89.15

January 2015 - December 2015

Sold Put

NYMEX-WTI

(1,593)

(89.15)

January 2016 - December 2016

Collars

NYMEX-WTI

732

70.00

90.55

As of December 31, 2014, we had the following net open natural gas derivative position:

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

January 2015 – December 2015	Swaps	NYMEX-HH	1,570		$4.31

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

Asset Derivative Instruments

Liability Derivative Instruments

December 31, 2014

June 30, 2014

December 31, 2014

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

$ 287,172

Current

$ 16,829

Current

$ 137,146

Current

$ 47,912

Non-Current

10,670

Non-Current

9,595

Non-Current

2,293

Non-Current

10,866

Commodity Derivative Instruments not designated as hedging instruments:

Derivative financial instruments

Current

551

Current

Non-Current

Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement

297,842

26,975

139,439

58,778

Derivative financial instruments

Current

(137,146)

Current

(15,955)

Current

(137,146)

Current

(15,955)

Non-Current

(2,293)

Non-Current

(6,560)

Non-Current

(2,293)

Non-Current

(6,560)

Gross amounts offset in Balance Sheets

(139,439)

(22,515)

(139,439)

(22,515)

Net amounts presented in Balance Sheets

Current

150,026

Current

1,425

Current

31,957

Non-Current

8,377

Non-Current

3,035

Non-Current

4,306

$ 158,403

$ 4,460

$—

$ 36,263

-18-

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

	Three Months Ended December 31,			Six Months Ended December 31,
		2014	2013		2014	2013
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales		$(44,947)	$ 1,397		$ (43,293)	$ 3,134
Natural gas sales		(1,300)	(3,448)		(1,469)	(6,227)
Total cash settlements		(46,247)	(2,051)		(44,762)	(3,093)

Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		(942)	6,112		(4,691)	7,674

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments
Realized mark to market (gain) loss		95	(645)		343	(1,219)
Unrealized mark to market (gain) loss		(39)	255		179	708
Total (gain) loss on derivative financial instruments		(886)	5,722		(4,169)	7,163
Total (gain) loss		$ (47,133)	$ 3,671		$ (48,931)	$ 4,070

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 December 31, 2014
Commodity Derivative Instruments	$	(93,625	)
Revenues				$	(33,296	)
Gain on derivative financial instruments							$	(942	)
Total (gain) loss	$	(93,625	)	$	(33,296	)	$	(942	)

Three Months Ended December 31, 2013
Commodity Derivative Instruments	$	11,190
Revenues				$	(5,432	)
Loss on derivative financial instruments							$	6,112
Total (gain) loss	$	11,190		$	(5,432	)	$	6,112

-19-


	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)
Six Months Ended December 31, 2014
Commodity Derivative Instruments	$	(129,328	)
Revenues				$	(34,589	)
Gain on derivative financial instruments							$	(4,691	)
Total (gain) loss	$	(129,328	)	$	(34,589	)	$	(4,691	)

Six Months Ended December 31, 2013
Commodity Derivative Instruments	$	30,692
Revenues				$	(10,208	)
Loss on derivative financial instruments							$	7,674
Total (gain) loss	$	30,692		$	(10,208	)	$	7,674

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 December 31, 2014
Unrealized gain on derivatives at beginning of period	$	(23,492	)	$	(15,269	)
Unrealized change in fair value		(194,321	)		(126,309	)
Ineffective portion reclassified to earnings during the period		(942	)		(612	)	Gain on derivative financial instruments
Realized amounts reclassified to earnings during the period		51,225			33,296		Revenues
Unrealized gain on derivatives at the end of period	$	(167,530	)	$	(108,894	)

Three months ended December 31, 2013
Unrealized gain on derivatives at beginning of period	$	(10,457	)	$	(6,797	)
Unrealized change in fair value		2,746			1,784
Ineffective portion reclassified to earnings during the period		6,112			3,973		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		8,357			5,432		Revenues
Unrealized loss on derivatives at end of period	$	6,758		$	4,392

-20-


	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Six months ended December 31, 2014
Unrealized loss on derivatives at beginning of period	$	31,436		$	20,434
Unrealized change in fair value		(247,489	)		(160,868	)
Ineffective portion reclassified to earnings during the period		(4,691	)		(3,049	)	Gain on derivative financial instruments
Realized amounts reclassified to earnings during the period		53,214			34,589		Revenues
Unrealized gain on derivatives at the end of period	$	(167,530	)	$	(108,894	)

Six months ended December 31, 2013
Unrealized gain on derivatives at beginning of period	$	(40,461	)	$	(26,300	)
Unrealized change in fair value		23,840			15,496
Ineffective portion reclassified to earnings during the period		7,674			4,988		Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		15,705			10,208		Revenues
Unrealized loss on derivatives at end of period	$	6,758		$	4,392

The amount expected to be reclassified from AOCI to net income in the next 12 months is a gain of $159.4 million ($103.6 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 December 31, 2014, 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, in the current period, we have recorded a $329 million Impairment of Goodwill (addressed in Note 4 of the Notes to Consolidated Financial Statements). In light of the form of the transaction related to the acquisition of EPL dated June 3, 2014, as stated in Note 3 of the Notes to Consolidated Financial Statements, “Acquisition of EPL Oil & Gas, Inc.”, the Goodwill recognized during fiscal year 2014 did not have tax basis, as such, the impairment is nondeductible for federal and state income tax purposes.

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


	Six Months Ended December 31,
	2014		2013

Cash paid for interest	$	111,208	$	60,917
Cash paid for income taxes		—		3,122

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


	Six Months Ended December 31,
	2014		2013

Financing of insurance premiums	$	2,148	$	2,355
Derivative instruments premium financing		7,305		3,493
Additions to property and equipment by recognizing asset retirement obligations		21,912		28,050

Note 12 — Related Party Transactions

During the six months ended December 31, 2014 and 2013, we paid dividends of $0.8 million and $150.1 million, respectively, to our Parent. During the six months ended December 31, 2014 and 2013, we returned net capital contributions of $19.9 million and $5.2 million, respectively, to our Parent.

On November 21, 2011, we advanced $65.0 million under a promissory note formalized on December 16, 2011 to Energy XXI, Inc. our indirect parent, bearing a simple interest of 2.78% per annum. The note matures on December 16, 2021. Energy XXI, Inc. has an option to prepay this note in whole or in part at any time, without any penalty or premium. Interest and principal are payable at maturity. Interest on the note receivable amounted to approximately $482,000 and $482,000 for the three months ended December 31, 2014 and 2013, respectively. Interest on the note receivable amounted to approximately $963,000 and $963,000 for the six months ended December 31, 2014 and 2013, respectively. Energy XXI, Inc. is subject to certain covenants related to investments, restricted payments and prepayments and was in compliance with such covenants as of December 31, 2014.

We reimbursed $3.6 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. Other services provided by Energy Services include legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the three months and six months ended December 31, 2014 was approximately $27.4 million and $32.0 million, respectively, and cost of these services for the three months and six months ended December 31, 2013 was approximately $14.8 million, $36.4 million, respectively and is included in general and administrative expense.

Prior to 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 six months ended December 31, 2014, we received management fees of $0.5 million and $1.4 million, respectively. For the three and six months ended December, 31, 2013, we received management fees of $1.1 million and $1.8 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.

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 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 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. Notwithstanding these bonds currently in place, the BOEM has the authority to require OCS operators such as us to obtain and maintain supplemental bonds issued to the agency that serve to further assure compliance with lease obligations, most notably, decommissioning obligations including the permanent plugging of wells and removal of platforms, pipelines and related facilities. Should the BOEM determine that supplemental bonding is required for decommissioning activities on one or more offshore leases, the agency generally will require the obligated lessee to obtain and maintain these supplemental bonds, which are issued to the BOEM. Alternatively, the BOEM may waive this requirement to obtain and maintain supplemental bonds if the agency determines that the operator meets certain demonstrations of financial strength and reliability. While we believe that the BOEM has waived the obligation to provide supplemental bonding based on such demonstrations, the BOEM retains the right to re-evaluate our decommissioning obligations or our market capitalization and asset impairments or otherwise amend the criteria that must be satisfied by an operator to qualify for waiver from supplemental bonding on the basis of financial strength and reliability and, as a result, determine that we no longer qualify for such waiver from the supplemental bonding requirements. For example, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for offshore oil and gas operations. The costs of satisfying 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 to support the issuance of these bonds or other surety. Such a letter of credit would likely be issued under the 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 any additional required bonds or assurances, 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.

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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.

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 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible 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 six months ended December 31, 2014, 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 December 31,			As of June 30,
	2014			2014
Assets:
Oil and natural gas derivatives		$	297,842		$	26,975

Liabilities:
Oil and natural gas derivatives		$	139,439		$	58,778

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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):

	December 31, 2014				June 30, 2014
		Carrying Value	Estimated Fair Value		Carrying Value			Estimated Fair Value
Revolving credit facility	$	941,309	$	941,309		$	689,000	$	689,000
8.25% Senior Notes due 2018		545,462		416,290			550,567		545,700
6.875% Senior Notes due 2024		650,000		359,130			650,000		663,000
7.5% Senior Notes due 2021		500,000		276,450			500,000		541,250
7.75% Senior Notes due 2019		250,000		152,750			250,000		269,480
9.25% Senior Notes due 2017		750,000		502,500			750,000		806,630
	$	3,636,771	$	2,648,429		$	3,389,567	$	3,515,060

Note 15 — Prepayments and Accrued Liabilities

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

	December 31,		June 30,
	2014		2014

Prepaid expenses and other current assets
Advances to joint interest partners	$	8,477	$	10,336
Insurance		15,403		36,451
Inventory		7,030		7,020
Royalty deposit		10,263		12,262
Other		5,031		3,298
Total prepaid expenses and other current assets	$	46,204	$	69,367

Accrued liabilities
Advances from joint interest partners	$	2,961	$	2,667
Interest payable		36,764		26,490
Accrued hedge payable		—		7,874
Undistributed oil and gas proceeds		23,988		34,473
Severance taxes payable		1,510		8,014
Other		3,614		5,644
Total accrued liabilities	$	68,837	$	85,162

Note 16 — Subsequent Events

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - February 12, 2015

Attached files

Energy XXI Ltd Reports