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

SEPTEMBER 30, 2014

ENERGY XXI GULF COAST, INC.

CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2014

C O N T E N T S

	Page

Consolidated Balance Sheets	3

Consolidated Statements of Income	4

Consolidated Statements of Comprehensive Income	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)

	September 30,			June 30,
ASSETS	2014			2014
	(Unaudited)
CURRENT ASSETS
Cash and cash equivalents	$	—		$	9,325
Receivables:
Oil and natural gas sales		145,821			167,075
Joint interest billings		14,426			12,898
Insurance and other		3,348			4,099
Prepaid expenses and other current assets		60,311			69,367
Deferred income taxes		24,587			52,011
Derivative financial instruments		23,815			1,425
TOTAL CURRENT ASSETS		272,308			316,200
Property and Equipment
Oil and gas properties-net – full cost method of accounting, including $1,167.6 million and $1,165.7 million of unevaluated properties not being amortized at September 30, 2014 and June 30, 2014, respectively		6,637,292			6,524,602
Other property and equipment		2,868			3,087
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment		6,640,160			6,527,689
Other Assets
Goodwill		329,293			329,293
Note receivable from Energy XXI, Inc.		70,327			69,845
Derivative financial instruments		6,713			3,035
Restricted cash		325			6,350
Debt issuance costs, net of accumulated amortization		48,290			42,155
Total Other Assets		454,948			450,678
TOTAL ASSETS	$	7,367,416		$	7,294,567
LIABILITIES
CURRENT LIABILITIES
Accounts payable	$	472,825		$	16,576
Accrued liabilities		90,602			85,162
Notes payable		19,368			21,967
Asset retirement obligations		79,614			79,649
Derivative financial instruments		1,446			31,957
Current maturities of long-term debt		14,591			14,094
TOTAL CURRENT LIABILITIES		678,446			649,405
Long-term debt, less current maturities		3,449,750			3,396,473
Deferred taxes		685,218			691,779
Asset retirement obligations		482,339			480,185
Derivative financial instruments	—				4,306
Other liabilities		2,454			2,454
TOTAL LIABILITIES		5,298,207			5,224,602
COMMITMENTS AND CONTINGENCIES (NOTE 12)
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		2,054,645			2,092,438
Accumulated deficit		(706	)		(2,040	)
Accumulated other comprehensive income, net of
income taxes		15,269			(20,434	)
TOTAL STOCKHOLDER’S EQUITY		2,069,209			2,069,965
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	7,367,416		$	7,294,567

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2014			2013

Revenues
Oil sales	$	368,501		$	289,229
Natural gas sales		34,730			35,363
Total Revenues		403,231			324,592

Costs and Expenses
Lease operating expense		142,585			85,763
Production taxes		3,093			1,398
Gathering and transportation		9,188			5,345
Depreciation, depletion and amortization		160,528			99,462
Accretion of asset retirement obligation		12,819			7,326
General and administrative expense		14,993			21,329
(Gain) loss on derivative financial instruments		(3,283	)		1,441
Total Costs and Expenses		339,923			222,064

Operating Income		63,308			102,528

Other Income (Expense)
Interest income		464			483
Interest expense		(60,050	)		(29,604	)
Total Other Expense		(59,586	)		(29,121	)

Income Before Income Taxes		3,722			73,407

Income Tax Expense		1,638			25,693

Net Income	$	2,084		$	47,714

See accompanying Notes to Consolidated Financial Statements

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Thousands)

(Unaudited)

	Three Months September 30,
	2014			2013

Net Income	$	2,084		$	47,714

Other Comprehensive Income (Loss)
Crude Oil and Natural Gas Cash Flow Hedges
Unrealized change in fair value net of ineffective portion		56,916			(22,656	)
Effective portion reclassified to earnings during the period		(1,988	)		(7,348	)
Total Other Comprehensive Income (Loss)		54,928			(30,004	)
Income Tax (Expense) Benefit		(19,225	)		10,501
Net Other Comprehensive Income (Loss)		35,703			(19,503	)

Comprehensive Income	$	37,787		$	28,211

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ENERGY XXI GULF COAST, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

	Three Months Ended
	September 30,
	2014			2013

Cash Flows from Operating Activities
Net income	$	2,084		$	47,714
Adjustments to reconcile net income to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization		160,528			99,462
Deferred income tax expense		1,638			25,693
Change in derivative financial instruments
Proceeds from sale of derivative instruments		3,364			—
Other – net		(5,938	)		(2,356	)
Accretion of asset retirement obligations		12,819			7,326
Amortization and write-off of debt issuance costs		2,159			1,455
Changes in operating assets and liabilities:
Accounts receivables		24,241			(2,238	)
Prepaid expenses and other current assets		9,056			(8,431	)
Asset retirement obligations		(14,907	)		(18,063	)
Accounts payable and other liabilities		49,536			(26,634	)
Net Cash Provided by Operating Activities		244,580			123,928

Cash Flows from Investing Activities
Acquisitions		(287	)		(15	)
Capital expenditures		(275,454	)		(197,369	)
Proceeds from the sale of properties		6,947			1,748
Net Cash Used in Investing Activities		(268,794	)		(195,636	)

Cash Flows from Financing Activities
Proceeds from long-term debt		510,120			1,040,697
Payments on long-term debt		(453,937	)		(865,128	)
Dividends to parent		(750	)		(82,000	)
Return to parent		(38,275	)		(13,126	)
Debt issuance costs		(2,269	)		(8,731	)
Other		—			(4	)
Net Cash Provided by Financing Activities		14,889			71,708

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

SEPTEMBER 30, 2014

(Unaudited)

Note 1 – Organization and Summary of Significant Accounting Policies

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”). 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. References in this report to “us,” “we,” “our,” or “the Company,” are to EGC and its wholly-owned subsidiaries.

Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of EGC and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated in consolidation.

Interim Financial Statements. The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“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. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such difference may be material.

Note 2 – Recent Accounting Pronouncements

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

In May 2014, the 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 and interim periods beginning after December 15, 2016. 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.

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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 public entities for annual and interim 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 position, results of operations or cash flows.

Note 3 – Acquisitions and Dispositions

Black Elk Interest

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

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

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

* Net working capital includes payables.

Walter Oil & Gas Corporation oil and gas properties interests acquisition

On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for a 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 acquisition of South Timbalier 54 Interests was accounted for under the acquisition method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):

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

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

-8-

Apache Joint Venture

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

The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through September 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014. As of September 30, 2014, our share of costs related to these wells was approximately $28.6 million.

Acquisition of 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 the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash ("Cash Election"), or 1.669 shares of Energy XXI common stock ("Stock Election") or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock ("Mixed Election") and collectively the ("Merger Consideration"), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, Energy XXI issued 23.3 million shares of its common stock and paid approximately $1,012 million in cash.

-9-

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

	EPL Historical			Fair Value Adjustment			Total
	(Unaudited)
Current assets (excluding deferred income taxes)	$	301,592		$	1,274		$	302,866
Oil and natural gas propertiesa
Evaluated (Including net ARO assets)		1,919,699			112,624			2,032,323
Unevaluated		41,896			859,886			901,782
Other property and equipment		7,787			-			7,787
Other assets		16,227			(9,002	)		7,225
Current liabilities (excluding ARO)		(314,649	)		(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. At September 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was unnecessary, and no goodwill impairment was recognized. 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 to 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 is retrospectively adjusted to increase the value of goodwill.

Costs associated with the EPL Acquisition totaled $13.6 million in the year ended June 30, 2014. EPL’s operating revenues and net income of $174.1 million and $10.7 million for the quarter ended September 30, 2014 are included in the Consolidated Statements of Income for the quarter ended September 30, 2014.

-10-

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

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

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

Goodwill arose subsequent to the EPL Acquisition 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 functions 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.

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.

-11-

Note 4 – Property and Equipment

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

	September 30,		June 30,
	2014		2014
Oil and gas properties
Proved properties	$	8,518,475	$	8,247,352
Less: accumulated depreciation, depletion, amortization and impairment		3,048,820		2,888,451
Proved properties		5,469,655		5,358,901
Unevaluated properties		1,167,637		1,165,701
Oil and gas properties		6,637,292		6,524,602

Other property and equipment		3,213		3,173
Less: accumulated depreciation		345		86
Other property and equipment		2,868		3,087
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	6,640,160	$	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, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with unproved properties are transferred to evaluated properties upon the earlier of 1) when a determination is made whether there are any proved reserves related to the properties, or 2) amortized over a period of time of not more than four years.

Exploratory wells in progress include $197.7 million in costs related to our participation with Freeport-McMoRan, Inc. who operates several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico. Activities related to certain of these well operations are controlled by the operator and these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.

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

Project Name	Cost		Status

Davy Jones Facilities	$	22.0	Facilities cost in Davy Jones field for well operations.
Davy Jones Offset Appraisal Well		70.2	Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands.
Blackbeard East		51.4	Plans to complete into the Miocene Sands in late 2015.
Lomond North		54.1	Completion operations in progress to test lower Wilcox and Cretaceous objectives
Total	$	197.7

Note 5 – Long-Term Debt

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

	September 30,		June 30,
	2014		2014

Revolving credit facility	$	748,264	$	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)		38,033		40,567
Derivative instruments premium financing		18,044		21,000
Total debt		3,464,341		3,410,567
Less current maturities		14,591		14,094
Total long-term debt	$	3,449,750	$	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 September 30, 2014 are as follows (in thousands):

Twelve Months Ended September 30,

2015	$	14,591
2016		3,453
2017		—
2018		2,046,297
2019		250,000
Thereafter		1,150,000
Total	$	3,464,341

Revolving Credit Facility

We entered into the second amended and restated first lien credit agreement (“First Lien Credit Agreement”) 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 our 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 September 30, 2014, we were in compliance with all covenants and had $748.3 million in borrowings and $226 million in letters of credit issued under our First Lien Credit Agreement.

High Yield Facilities

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 consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the merger agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the consent time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked. The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.

We believe that the fair value of the $510 million of 8.25% Senior Notes outstanding as of September 30, 2014 was $519.1 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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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. We incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes.

On or after March 15, 2019, 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 Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. 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 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.

The indenture governing the 6.875% Senior Notes will, among other things, 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.

We believe that the fair value of the $650 million of 6.875% Senior Notes outstanding as of September 30, 2014 was $617.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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 for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. We incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.5% Senior Notes.

On or after December 15, 2016, 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 the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.5% Senior Notes.

The indenture governing the 7.5% Senior Notes 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, 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.

We believe that the fair value of the $500 million of 7.5% Senior Notes outstanding as of September 30, 2014 was $494.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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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 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. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. 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 is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.

We believe that the fair value of the $750 million of 9.25% Senior Notes outstanding as of September 30, 2014 was $775.8 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

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 of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.

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

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

We believe that the fair value of the $250 million of 7.75% Senior Notes outstanding as of September 30, 2014 was $250.4 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.

Guarantee of Securities Issued by EGC

We are the issuer of each of the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by us and each of our existing and future material domestic subsidiaries other than EPL and its subsidiaries. Energy XXI and its subsidiaries, other than us, do not have significant independent assets or operations. We are permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility.”

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Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of September 30, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $18 million and $21 million, respectively.

Interest Expense

For the three months ended September 30, 2014 and 2013, interest expense consisted of the following (in thousands):

	Three Months Ended September 30,
	2014			2013

Revolving credit facility	$	6,893		$	5,219
9.25% Senior Notes due 2017		17,344			17,344
8.25% Senior Notes due 2018		10,519			-
7.75% Senior Notes due 2019		4,844			4,844
7.50% Senior Notes due 2021		9,375			521
6.875% Senior Notes due 2024		11,172			-
Amortization of debt issue cost - Revolving credit facility		977			806
Amortization of debt issue cost – 9.25% Senior Notes due 2017		552			552
Amortization of fair value premium – 8.25% Senior Notes due 2018		(2,534	)		-
Amortization of debt issue cost – 7.75% Senior Notes due 2019		97			97
Amortization of debt issue cost – 7.50% Senior Notes due 2021		263			-
Amortization of debt issue cost – 6.875% Senior Notes due 2024		281			-
Derivative instruments financing and other		267			221
	$	60,050		$	29,604

Note 6 – Notes Payable

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

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

On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of September 30, 2014 was $16.0 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 September 30, 2014 was $3.4 million.

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Note 7 – 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		5,372
Liabilities settled		(14,907	)
Liabilities sold		(1,165	)
Accretion expense		12,819
Total balance at September 30, 2014		561,953
Less current portion		79,614
Long-term balance at September 30, 2014	$	482,339

Note 8 – Derivative Financial Instruments

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

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

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

Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). During the quarter ended September 30, 2011, the Company began including ICE Brent Futures (“Brent”) collars and three-way collars in our hedging portfolio. By including Brent benchmarks in our crude hedging, we can appropriately manage our exposure and price risk. In April 2014, we began including Argus-LLS futures collars in our hedging portfolio to appropriately align and manage our exposure and price risk to market conditions.

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

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.

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We have monetized certain hedge positions at various times since the quarter ended March 31, 2009 through the quarter ended June 30, 2013, and received $181.3 million. During the quarter ended September 30, 2014, we monetized certain of our hedge positions and received $3.4 million. These monetized amounts were recorded in stockholders’ equity as part of other comprehensive income (“OCI”) and are recognized in income over the contract life of the underlying hedge contracts. As of September 30, 2014, we had $3.4 million of monetized amounts remaining in OCI of which $1.2 million, $1 million, $0.9 million and $0.3 million will be recognized in income during the quarters ending in December 31, 2014, March 31, 2015, June 30, 2015 and September 30, 2015, respectively.

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

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

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

October 2014 - December 2014	Three-Way Collars	Oil-Brent-IPE		490			$	68.44	$	88.44	$	128.56
October 2014 - December 2014	Put Spreads	Oil-Brent-IPE		109				66.43		86.43
October 2014 - December 2014	Collars	Oil-Brent-IPE		184						90.00		108.38
October 2014 - December 2014	Put Spreads	NYMEX-WTI		310				70.00		90.00
October 2014 - December 2014	Three-Way Collars	NYMEX-WTI		610				70.00		90.00		137.20
October 2014 - December 2014	Swaps	ARGUS-LLS		712	$	91.95
January 2015 - December 2015	Three-Way Collars	Oil-Brent-IPE		3,650				71.00		91.00		113.75
January 2015 - December 2015	Swaps	Oil-Brent-IPE		548		97.70
January 2015 - December 2015	Collars	ARGUS-LLS		1,825						80.00		123.38
January 2015 - December 2015	Put Spreads	NYMEX-WTI		2,728						89.18

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

Weighted Average Contract Price

Swaps

Collars/Put Spreads

Period

Type of Contract

Index

Volumes

(MMBtu)

Fixed Price

Sub Floor

Floor

Ceiling

October 2014 - December 2014

Three-Way Collars

NYMEX-HH

4,197

3.36

4.00

4.60

October 2014 - December 2014

Put Spreads

NYMEX-HH

403

3.25

4.00

October 2014 - December 2014

Swaps

NYMEX-HH

460

4.01

January 2015 – December 2015

Swaps

NYMEX-HH

1,570

4.31

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

	Asset Derivative Instruments								Liability Derivative Instruments
	September 30, 2014				June 30, 2014				September 30, 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	$	31,043		Current	$	16,829		Current	$	8,769		Current	$	47,912
		Non-Current		9,140		Non-Current		9,595		Non-Current		2,397		Non-Current		10,866

Commodity Derivative Instruments not designated as hedging instruments:
Derivative financial instruments		Current		95		Current		551		Current		—		Current		—
		Non-Current		—		Non-Current		—		Non-Current		—		Non-Current		—
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement				40,248				26,975				11,166				58,778

Derivative financial instruments		Current		(7,323)		Current		(15,955)		Current		(7,323)		Current		(15,955)
		Non-Current		(2,397)		Non-Current		(6,560)		Non-Current		(2,397)		Non-Current		(6,560)
Gross amounts offset in Balance Sheets				(9,720)				(22,515)				(9,720)				(22,515)
Net amounts presented in Balance Sheets		Current		23,815		Current		1,425		Current		1,446		Current		31,957
		Non-Current		6,713		Non-Current		3,035		Non-Current		—		Non-Current		4,306
			$	30,528			$	4,460			$	1,446			$	36,263

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

	Three Months Ended September 30,
	2014			2013
Location of (Gain) Loss in Income Statement
Cash Settlements, net of amortization of purchased put premiums:
Oil sales	$	1,654		$	1,736
Natural gas sales		(169	)		(2,779	)
Total cash settlements		1,485			(1,043	)

Commodity Derivative Instruments designated as hedging instruments:
(Gain) loss on derivative financial instruments Ineffective portion of commodity derivative instruments		(3,749	)		1,562

Commodity Derivative Instruments not designated as hedging instruments:
(Gain) loss on derivative financial instruments Realized mark to market (gain) loss		248			(574	)
Unrealized mark to market (gain) loss		218			453
Total (gain) loss on derivative financial instruments		(3,283	)		1,441
Total (gain) loss	$	(1,798	)	$	398

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

Location of (Gain) Loss	Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss, net of tax (Effective Portion)			Amount of (Gain) Loss on Derivative Instruments Reclassified from Other Comprehensive (Income) Loss (Ineffective Portion)
Three Months Ended September 30, 2014
Commodity Derivative Instruments	$	(35,703	)
Revenues				$	(1,292	)
(Gain) loss on derivative financial instruments							$	(3,749	)
Total (gain) loss	$	(35,703	)	$	(1,292	)	$	(3,749	)

Three Months Ended September 30, 2013
Commodity Derivative Instruments	$	19,503
Revenues				$	(4,776	)
(Gain) loss on derivative financial instruments							$	1,562
Total (gain) loss	$	19,503		$	(4,776	)	$	1,562

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

	Before Tax			After Tax			Location Where Consolidated Net Income is Presented
Three months ended September 30, 2014
Unrealized loss on derivatives at beginning of period	$	31,436		$	20,434
Unrealized change in fair value		(53,167	)		(34,559	)
Ineffective portion reclassified to earnings during the period		(3,749	)		(2,436	)	(Gain) Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		1,988			1,292		Revenues
Unrealized gain on derivatives at end of period	$	(23,492	)	$	(15,269	)

Three months ended September 30, 2013
Unrealized gain on derivatives at beginning of period	$	(40,464	)	$	(26,300	)
Unrealized change in fair value		21,094			13,711
Ineffective portion reclassified to earnings during the period		1,562			1,015		(Gain) Loss on derivative financial instruments
Realized amounts reclassified to earnings during the period		7,348			4,777		Revenues
Unrealized gain on derivatives at end of period	$	(10,460	)	$	(6,797	)

The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $20.4 million ($13.3 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At September 30, 2014, we had no deposits for collateral with our counterparties.

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Note 9 – 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 United States; accordingly, income taxes have been provided based upon the tax laws and rates of the United States as they apply to our current ownership structure. ASC Topic 740 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated 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.

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.

Note 10 – Supplemental Cash Flow Information

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

	Three Months Ended September 30,
	2014		2013

Cash paid for interest	$	41,758	$	5,696
Cash paid for income taxes		280		2,856

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

	Three Months Ended September 30,
	2014		2013

Financing of insurance premiums	$	3,358	$	2,355
Derivative instruments premium financing		-		698
Additions to property and equipment by recognizing
asset retirement obligations		4,207		14,151

Note 11 – Related Party Transactions

During the three months ended September 30, 2014 and 2013, we paid dividends of $0.8 million and $82 million, respectively, to our Parent. During the three months ended September 30, 2014 and 2013, we returned net capital contributions of $38.3 million and $13.1 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 $481,000 for the three months ended September 30, 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 September 30, 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.

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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 both the three months ended September 30, 2014 and 2013 was approximately $4.6 million and $21.6 million, 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 purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three months ended September 30, 2014 and 2013, we received management fees of $0.9 million and $0.7 million, respectively.

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

Note 12 – 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, and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

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

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

Letters of Credit and Performance Bonds. We had $226 million in letters of credit and $170.5 million of performance bonds outstanding as of September 30, 2014.

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

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

2) September 1, 2013 to November 30, 2014 at $130,000 per day

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

4) February 15, 2014 to December 29, 2014 at $111,380 per day

5) April 11, 2014 to October 12, 2014 at $112,000 per day

6) July 1, 2014 to October 21, 2014 at $107,500 per day.

7) October 4, 2014 to November 4, 2014 at $107,500 per day.

At September 30, 2014, future minimum commitments under these contracts totaled $34.8 million.

Note 13 — Fair Value of Financial Instruments

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

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

Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 8 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

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.

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

	Level 2
	As of September 30,		As of June 30,
	2014		2014

Assets:
Oil and natural gas derivatives	$	40,248	$	26,975

Liabilities:
Oil and natural gas derivatives	$	11,166	$	58,778

Note 14 — Prepayments and Accrued Liabilities

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

	September 30,		June 30,
	2014		2014

Prepaid expenses and other current assets
Advances to joint interest partners	$	10,821	$	10,336
Insurance		28,278		36,451
Inventory		7,168		7,020
Royalty deposit		11,832		12,262
Other		2,212		3,298
Total prepaid expenses and other current assets	$	60,311	$	69,367

Accrued liabilities
Advances from joint interest partners	$	2,831	$	2,667
Interest payable		44,692		26,490
Accrued hedge payable		1,761		7,874
Undistributed oil and gas proceeds		31,345		34,473
Severance taxes payable		2,021		8,014
Other		7,952		5,644
Total accrued liabilities	$	90,602	$	85,162

Note 15 — Subsequent Event

In October 2014 and in November 2014, we monetized certain WTI put contracts and certain Brent swap contracts related to calendar year 2015 and realized $21.3 million and $7.5 million, respectively. These monetized amounts will be recorded in stockholder’s equity as part of OCI and will be recognized in income over the contract life of the underlying hedge contracts during calendar year 2015.

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Energy XXI Ltd - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - November 14, 2014

Attached files

Energy XXI Ltd Reports