UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q


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

For the quarterly period ended December 31, 2015
or


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

Commission file number: 001-16179

EPL Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)


Delaware		72-1409562
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


1021 Main Street, Suite 2626, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 351-3000

Registrant’s telephone number, including area code

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer o		Accelerated filer o
Non-accelerated filer x (Do not check if a smaller reporting company)		Smaller reporting company o

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No o

There is no market for the common stock of EPL Oil & Gas, Inc.

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	Page
PART I — FINANCIAL INFORMATION
Item 1. Unaudited Consolidated Financial Statements		1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3. Quantitative and Qualitative Disclosures about Market Risk		45
Item 4. Controls and Procedures		46
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		47
Item 1A. Risk Factors		47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		51
Item 3. Defaults Upon Senior Securities		51
Item 4. Mine Safety Disclosures		51
Item 5. Other Information		51
Item 6. Exhibits		51
SIGNATURES		52
EXHIBIT INDEX		53

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this quarterly report on Form 10-Q (this “Quarterly Report”) may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances and their potential effect on us. While management believes that these forward-looking statements are reasonable, such statements are not guarantees of future performance and the actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

our business strategy;

•

further or sustained declines in the prices we receive for our oil and gas production;

•

our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

•

our future financial condition, results of operations, revenues, cash flows and expenses;

•

the potential need to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection;

•

our future levels of indebtedness, liquidity, compliance with financial covenants and our ability to continue as a going concern;

•

the size of our borrowing base under our parent’s second amended and restated first lien credit agreement, any reduction in which would result in a deficiency that would have to be repaid within 45 days;

•

our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations;

•

our ability to post additional collateral for current bonds or comply with new supplemental bonding requirements imposed by the Bureau of Ocean Energy Management (the “BOEM”);

•

economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;

•

uncertainties in estimating oil and gas reserves and net present values of those reserves;

•

the need to take ceiling test impairments due to lower commodity prices;

•

hedging activities exposing us to pricing and counterparty risks;

•

replacing oil and gas reserves;

•

geographic concentration of our assets;

•

uncertainties in exploring for and producing oil and gas, including exploitation, development, drilling and operating risks;

•

our ability to make acquisitions and to integrate acquisitions;

•

our ability to establish production on our acreage prior to the expiration of related leaseholds;

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•

availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;

•

disruption of operations and damages due to capsizing, collisions, hurricanes or tropical storms;

•

environmental risks;

•

availability, cost and adequacy of insurance coverage;

•

competition in the oil and gas industry;

•

our inability to retain and attract key personnel;

•

the effects of government regulation and permitting and other legal requirements;

•

costs associated with perfecting title for mineral rights in some of our properties; and

•

weaknesses in our internal controls.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended June 30, 2015 (the “2015 Annual Report”) and Part II, “Item 1A. Risk Factors” in this Quarterly Report.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date upon which they are made, whether as a result of new information, future events or otherwise.

iii

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PART I — FINANCIAL INFORMATION

Item 1.

Unaudited Consolidated Financial Statements.

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)


	December 31, 2015			June 30, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	217
Trade accounts receivable – net		42,480			71,323
Derivative financial instruments		—			888
Restricted cash		6,025			6,024
Prepaid expenses		2,631			1,831
Total current assets		51,136			80,283
Property and equipment, net – full cost method of accounting, including $45.5 million and $435.4 million of unevaluated properties not being amortized at December 31, 2015 and June 30, 2015, respectively		481,426			1,415,025
Restricted cash		30,008			—
Other assets and debt issuance costs, net of accumulated amortization		1,036			1,039
Total assets	$	563,606		$	1,496,347
LIABILITIES AND STOCKHOLDER’S DEFICIT
Current liabilities:
Accounts payable	$	33,076		$	24,548
Due to EGC		202,767			170,728
Accrued liabilities		94,567			95,981
Asset retirement obligations		29,077			38,056
Derivative financial instruments		—			1,057
Current maturities of long-term debt		—			3,364
Total current liabilities		359,487			333,734
Long-term debt, less current maturities		651,462			689,459
Promissory note payable to EGC		325,000			325,000
Asset retirement obligations		160,909			202,306
Total liabilities		1,496,858			1,550,499
Commitments and contingencies (Note 11)
Stockholder’s deficit:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at December 31, 2015 and June 30, 2015		—			—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; shares issued and outstanding: 1,000 at December 31, 2015 and June 30, 2015		—			—
Additional paid-in capital		1,599,341			1,599,341
Accumulated deficit		(2,532,593	)		(1,653,493	)
Total stockholder’s deficit		(933,252	)		(54,152	)
Total liabilities and stockholder’s deficit	$	563,606		$	1,496,347

See accompanying Notes to Consolidated Financial Statements.

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EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(In thousands)


	Three Months Ended December 31,						Six Months Ended December 31,
	2015			2014			2015			2014
Revenues
Oil sales	$	54,408		$	120,828		$	127,780		$	279,144
Natural gas sales		8,256			12,548			20,874			26,502
Gain on derivative financial instruments		906			22,262			3,684			44,119
Total Revenues		63,570			155,638			152,338			349,765
Costs and expenses
Lease operating		30,889			55,304			57,042			111,604
Transportation		664			1,149			1,387			1,774
Depreciation, depletion and amortization		62,333			88,547			119,993			162,292
Accretion of asset retirement obligations		6,317			6,098			13,058			12,279
Impairment of oil and natural gas properties		504,772			690,312			812,850			690,312
Goodwill impairment		—			—			—			329,293
General and administrative expense		9,978			6,810			17,922			14,852
Taxes, other than on earnings		39			1,944			(896	)		4,472
Other		—			—			—			21
Total costs and expenses		614,992			850,164			1,021,356			1,326,899
Operating Loss		(551,422	)		(694,526	)		(869,018	)		(977,134	)
Other income (expense):
Other income, net		2,393			4			2,405			4
Gain on early extinguishment of debt		21,269			—			21,269			—
Interest expense		(16,772	)		(10,947	)		(33,756	)		(21,848	)
Total other income (expense), net		6,890			(10,943	)		(10,082	)		(21,844	)
Loss before income taxes		(544,532	)		(705,469	)		(879,100	)		(998,978	)
Income tax benefit		—			(250,857	)		—			(238,010	)
Net loss	$	(544,532	)	$	(454,612	)	$	(879,100	)	$	(760,968	)

See accompanying Notes to Consolidated Financial Statements.

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EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(In thousands)


	Six Months Ended December 31,
	2015			2014
Cash flows from operating activities:
Net loss	$	(879,100	)	$	(760,968	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		119,993			162,292
Accretion of asset retirement obligations		13,058			12,279
Gain on early extinguishment of debt		(21,269	)		—
Change in fair value of derivative financial instruments		(1,573	)		(14,657	)
Deferred income taxes		—			(238,010	)
Impairment of oil and natural gas properties		812,850			690,312
Goodwill impairment		—			329,293
Amortization of premium and debt issuance costs		(6,532	)		(5,104	)
Changes in operating assets and liabilities:
Trade accounts receivable		26,776			9,721
Prepaid expenses and other assets		(800	)		16,762
Accounts payable and accrued liabilities		12,687			(70,981	)
Asset retirement obligation settlements		(48,627	)		(32,038	)
Net cash provided by operating activities		27,463			98,901
Cash flows used in investing activities:
Property acquisitions		—			(350	)
Capital expenditures		(16,122	)		(239,090	)
Other property and equipment additions		—			(58	)
Net cash used in investing activities		(16,122	)		(239,498	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt		(3,395	)		—
Cash restricted under revolving credit facility		(30,008	)		—
Advances from EGC		22,034			135,480
Debt issuance costs		(189	)		—
Net cash provided by (used in) financing activities		(11,558	)		135,480
Net decrease in cash and cash equivalents		(217	)		(5,117	)
Cash and cash equivalents at beginning of period		217			5,601
Cash and cash equivalents at end of period	$	—		$	484
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Non-cash investing information:
Changes in capital expenditures accrued in accounts payable	$	(2,071	)	$	(49,814	)
Changes in asset retirement obligations		(14,807	)		5,212
Cash paid during the period for:
Interest	$	24,679		$	26,948

See accompanying Notes to Consolidated Financial Statements.

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations. EPL Oil & Gas, Inc. (referred to herein as “we,” “our,” “us,” “EPL” or “the Company”) was incorporated as a Delaware corporation on January 29, 1998 and is a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation and an indirect wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of Bermuda and our ultimate parent company (“Energy XXI” or “parent”). We operate as an independent oil and natural gas exploration and production company with our current operations concentrated in the U.S. Gulf of Mexico shelf (the “GoM shelf”) focusing on state and federal waters offshore Louisiana, which we consider our core area.

Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of EPL and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions 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 consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2015 Annual Report.

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 estimates used in accounting for acquisitions and dispositions; 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 the 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.

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.

In August 2014, the FASB issued ASU 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

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 1 — Organization and Summary of Significant Accounting Policies – (continued)

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. Our early adoption of ASU 2014-15 during the quarter ended December 31, 2015 impacted our disclosures but had no effect on our consolidated financial position, results of operations or cash flows.

In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. In June 2015, the FASB issued ASU 2015-15 as an amendment to this guidance to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements. The SEC staff stated that they would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.

The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.

In November 2015, the FASB issued ASU. No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred taxes on the balance sheet by requiring classification of all deferred tax items as noncurrent including valuation allowances by jurisdiction. The ASU is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is permitted as of the beginning of any interim or annual reporting period. Our early adoption of ASU 2015-17 during the quarter ended December 31, 2015 had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

Note 2 — Liquidity and Capital Resources

Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. However, future cash flows are subject to a number of variables, and are highly dependent on the prices we receive for oil and natural gas. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As of December 31, 2015, we had $150 million in borrowings outstanding under the second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility” or “Revolver”), to which we are a party with EGC, and we were in compliance with our financial covenants; however, based on current market conditions and depressed commodity prices, if Energy XXI is unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016. In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency and we must remain in compliance with the financial ratios in the Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

Energy XXI is evaluating various alternatives with respect to the Revolving Credit Facility, but there is no certainty that it will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach 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. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI’s 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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

EGC may face other impediments to accessing available borrowing capacity under the Revolving Credit Facility. Borrowings under the First Lien Credit Agreement are limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we, EGC and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base available to EPL of $150 million (the “Revolving Credit EPL Sub-Facility), although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. As of December 31, 2015, we had fully utilized amounts available under the Revolving Credit EPL Sub-Facility. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit EPL Sub-Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness in excess of any reduced borrowing base.

In addition, in response to commodity price declines, our fiscal year 2016 capital budget was substantially reduced compared to actual capital expenditures in fiscal year 2015. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. The curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

We may experience a further strain on our liquidity if the BOEM requires us to provide additional bonding as a means to assure our decommissioning obligations, such as the plugging of wells, the removal of platforms and other facilities, the abandonment of pipelines and the clearing of the seafloor of obstructions, or if the surety companies providing such bonds on our behalf require us to provide additional cash collateral for

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

such bonds. Any further expense in providing additional bonds or restrictions on our cash to collateralize existing bonds or new bonds would further reduce our liquidity.

Beginning on January 11, 2016, Energy XXI’s common stock has generally traded on NASDAQ at less than $1.00 per share. Due to certain NASDAQ requirements, there is no assurance that the price of Energy XXI’s common stock will comply with the requirements for continued listing of its shares on NASDAQ. A delisting of Energy XXI’s common stock could constitute a “fundamental change” under the terms of its $400 million aggregate principal amount of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). If such a fundamental change occurs at any time prior to the maturity of the 3.0% Senior Convertible Notes, each holder of such notes shall have the right to require Energy XXI to repurchase all or part of such holder’s 3.0% Senior Convertible Notes in accordance with the terms of the 3.0% Senior Convertible Notes. We cannot assure that Energy XXI would have adequate liquidity to fund such a repurchase given its severe liquidity constraints. Such acceleration would cause a cross-default or cross-acceleration of all of Energy XXI’s other outstanding indebtedness, including our 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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

As described below under Note 6 — Indebtedness, we had total indebtedness of $976.5 million as of December 31, 2015, and taking into account bond repurchases subsequent to December 31, 2015 of approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes due 2018 (the “8.25% Senior Notes”), we had total indebtedness of $697.1 million as of February 15, 2016. All of our outstanding indebtedness will mature within the next three years. In addition, the Revolving Credit Facility is scheduled to mature on April 9, 2018; however, the maturity of the Revolving Credit Facility will accelerate if EGC’s 9.25% Senior Notes due 2017 (the “9.25% Senior Notes”) are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. All of the factors described above have placed considerable pressure on our ability to pay the principal and interest on our long-term debt, satisfy our other liabilities, continue our development activities to maintain and grow reserves and our ability to refinance our debt as it becomes due.

As a result of the commodity price decline and the Company’s substantial debt burden, absent a material improvement in oil and gas prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, the Company believes forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months. This raises substantial doubt regarding the Company’s ability to continue as a going concern.

In February 2016, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P as a legal advisor to advise its management and Board of Directors (the “Board”), EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Energy XXI is also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows.

As a result of the commodity price decline, we will continue to evaluate our ability to make the debt payments as they become due and to meet the additional supplemental bonding requirements of the BOEM and our surety companies’ requirements to provide additional cash collateral for such existing and future bonds in light of our liquidity constraints. On February 16, 2016, we elected to enter into the 30-day grace

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

period under the terms of the indenture governing our outstanding 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing the 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit EPL Sub-Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities.

Note 3 — Pushdown Accounting and Goodwill

On June 3, 2014, Energy XXI, EGC, Clyde Merger Sub, Inc., a wholly owned subsidiary of EGC (“Merger Sub”), and EPL, completed the transactions contemplated by the Agreement and Plan of Merger, dated as of March 12, 2014 (as amended, the “Merger Agreement”), by and among Energy XXI, EGC, Merger Sub, and EPL, pursuant to which Merger Sub was merged with and into EPL with EPL continuing as the surviving corporation (the “Merger”). Pursuant to the Merger Agreement, at the effective time of the Merger (the “Effective Time”), the issued and outstanding shares of EPL common stock, par value $0.001 per share (“EPL Common Stock”), were converted, in the aggregate, into the right to receive merger consideration (the “Merger Consideration”) consisting of approximately 65% in cash and 35% in shares of common stock of Energy XXI, par value $0.005 per share (“Energy XXI Common Stock”). The Merger resulted in EPL becoming an indirect, wholly owned subsidiary of Energy XXI. Therefore, in the preparation of our financial statements, we have applied “pushdown” accounting, based on guidance from the Securities and Exchange Commission (“SEC”). Pushdown accounting refers to the use of the acquiring entity’s basis of accounting in the preparation of the acquired entity’s financial statements.

In accordance with the acquisition method of accounting, the purchase price established in the Merger was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. 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 Merger is not deductible for income tax purposes.

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

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Note 3 — Pushdown Accounting and Goodwill – (continued)

or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed during the third quarter each fiscal year.

Impairment testing for goodwill is performed 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 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 necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital used to estimate fair value, 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 was 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 September 30, 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 rate based on market participant data. The estimation of the fair value of our reporting unit 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 beyond a certain period and estimated future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.

Note 4 — Property and Equipment

The following table summarizes our property and equipment.


	December 31, 2015			June 30, 2015
	(In thousands)
Proved oil and natural gas properties	$	3,385,252		$	2,993,012
Unevaluated oil and natural gas properties		45,549			435,429
Other		—			3,116
Less: accumulated depreciation, depletion, amortization and impairment		(2,949,375	)		(2,016,532	)
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	481,426		$	1,415,025

At December 31, 2015 and June 30, 2015, our investment in unevaluated properties primarily relates to the fair value of unproved oil and natural gas properties determined during the Merger. 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) ratably over a period of time of not more

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Note 4 — Property and Equipment – (continued)

than four years. In the six months ended December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, we believe that all of our proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the three and six months ended December 31, 2015, our ceiling test computation resulted in impairments of our oil and natural gas properties of $504.8 million and $812.9 million, respectively. If the current low commodity price environment or downward trend in oil prices continues, we will incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

Note 5 — Asset Retirement Obligations

The following table reconciles the changes to our asset retirement obligations.


	Six Months Ended December 31, 2015
	(in thousands)
Beginning of period total	$	240,362
Accretion expense		13,058
Liabilities incurred		3,457
Revisions*		(18,264	)
Liabilities settled		(48,627	)
End of period total		189,986
Less: End of period, current portion		(29,077	)
End of period, noncurrent portion	$	160,909

This downward revision was primarily due to declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services due to excess capacity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness

The following table sets forth our indebtedness.


	December 31, 2015		June 30, 2015
	(In thousands)
8.25% Senior Notes due 2018	$	480,244	$	510,000
Debt premium on 8.25% Senior Notes due 2018		21,218		29,459
Revolving Credit EPL Sub-Facility		150,000		150,000
Derivative instruments premium financing		—		3,364
Total debt		651,462		692,823
Less current maturities		—		(3,364	)
Long term debt		651,462		689,459
Promissory note payable to EGC		325,000		325,000
Noncurrent portion of indebtedness	$	976,462	$	1,014,459

During October 2015, we repurchased $29.8 million in aggregate principal amount of the 8.25% Senior Notes in open market transactions at a total price of approximately $10.0 million, and we recorded a gain on this repurchase of approximately $21.3 million, including the amount of associated unamortized premium, during the three months ended December 31, 2015. The repurchased notes were cancelled. Subsequent to December 31, 2015, we repurchased approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes in open market transactions at a total price of approximately $11.4 million, including accrued interest of $10.4 million, reducing our total indebtedness to approximately $697.1 million as of February 15, 2016. See below for further discussion of our 8.25% Senior Notes.

Revolving Credit EPL Sub-Facility

The Revolving Credit Facility underwent its Twelfth Amendment to the First Lien Credit Agreement on November 30, 2015 (the “Twelfth Amendment”) and its Eleventh Amendment and Waiver to the First Lien Credit Agreement was on July 31, 2015 (the “Eleventh Amendment”). The Revolving Credit Facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base under the sub-facility established for EPL, although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. These respective borrowing bases were set in accordance with the regular annual process for determination of the borrowing bases and the borrowing bases are to remain in effect until the next redetermination thereof under the terms of the First Lien Credit Agreement. Borrowings under the First Lien Credit Agreement are also limited to a borrowing base based on oil and natural gas reserve values, which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we, EGC and the lenders completed the fall borrowing base redetermination with no changes to the existing borrowing base at $500 million, and the lenders temporarily relaxed the requirements of certain financial covenants under the Twelfth Amendment as described below. The scheduled date of maturity of the First Lien Credit Agreement is April 9, 2018, provided however that the maturity date will accelerate to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% Senior Notes if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of our outstanding 8.25% Senior Notes if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit Facility borrowing base and commitment

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness – (continued)

amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness in excess of any reduced borrowing base.

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

Borrowings are limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. The Revolving Credit Facility is secured by mortgages on at least 90% of the value of EGC and its subsidiaries’ (other than EPL and its subsidiaries until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but with the threshold for such properties of EPL and its subsidiaries (until they shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%. Additionally, as a result of the Twelfth Amendment, we are required to maintain $30 million of restricted cash in an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement.

Currently, the facility bears interest based on the borrowing base usage, at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%. The applicable commitment fee under the facility is 0.50%.

The First Lien Credit Agreement contains certain restrictions on the prepayment and repayment of outstanding note indebtedness of EGC and its subsidiaries, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that EGC have net liquidity at the time thereof of at least $250 million. In addition, EGC is required to have pro forma net liquidity of $250 million at the time of any refinancing of outstanding indebtedness.

Lender consent is required for any asset disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate. The Eleventh Amendment waived certain provisions of the First Lien Credit Agreement to permit EGC to acquire the remaining equity interests of M21K, LLC as well as an additional minor acquisition and disposition.

The First Lien Credit Agreement requires that EPL and EGC maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. We are currently subject to the following financial covenants: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. If the 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a minimum current ratio of no less than 1.0 to 1.0.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness – (continued)

Additionally, the following changes became effective upon the execution of the Twelfth Amendment:

•

Modification of triggers that require EPL and its subsidiaries to provide guarantees of the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees. Under such modifications, such guarantees and security will be required upon the earlier of EPL’s retirement of its obligations in respect of its outstanding 8.25% Senior Notes and amendments to covenant restrictions under such notes that eliminate restrictions on the ability of EPL and its subsidiaries to guarantee the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees (even if such notes have not been refinanced or defeased).

•

Suspending the maximum net secured leverage ratio covenant with respect to EGC and its subsidiaries (other than EPL and its subsidiaries) to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.

•

Suspending the maximum net secured leverage ratio covenant with respect to EPL and its subsidiaries to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.

•

Modifying the maximum net secured leverage covenant with respect to EGC and its subsidiaries to be 3.75:1.00 as of the end of each fiscal quarter beginning with the fiscal quarter ended September 30, 2015, increasing to 4.75:1.00 starting March 31, 2016 and to 5.25:1.00 starting June 30, 2016, and decreasing to 5.00:1.00 beginning June 30, 2017 and thereafter.

As of December 31, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, and we were in compliance with all covenants thereunder. Due to current market conditions and depressed commodity prices, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and Board, EGC and EPL regarding potential strategic alternatives to address the Company’s liquidity concerns and high debt levels. Based on current market conditions and depressed commodity prices, if it is unable to execute on one of the strategic alternatives being evaluated and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio under our Revolving Credit Facility for the quarter ending March 31, 2016. Due to our election on February 16, 2016 to enter into the 30-day grace period for making interest payment under the terms of the indenture governing our outstanding 8.25% Senior Notes, certain restrictions, as fully described below under the caption 8.25% Senior Notes Due 2018, have been placed on the Company. In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in the Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness – (continued)

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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

Promissory Note

On March 12, 2015, in connection with EGC’s issuance of its 11.0% senior secured second lien notes due 2020 (the “11.0% Notes”), we entered into a $325.0 million secured second lien promissory note between us, as the maker, and EGC, as the payee (the “Promissory Note”). Proceeds from the Promissory Note were used to repay a like amount of the outstanding borrowings under the Revolving Credit EPL Sub-Facility. The Promissory Note bears interest at an annual rate of 10%, has a maturity date of October 9, 2018, and is secured by a second priority lien on certain of our assets that secure the obligations under the First Lien Credit Agreement. EGC may release the collateral securing the Promissory Note at any time. The note has not been, and will not be, registered under the Securities Act of 1933, as amended or the securities laws of any other jurisdiction. We have an option to prepay this note in whole or in part at any time, without penalty or premium. The note bears interest from the date of issuance with interest due quarterly, in arrears, on January 5^th, April 5^th, July 5^th, and October 5^th, beginning September 5, 2015.

8.25% Senior Notes due 2018

The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount ($501.5 million carrying value at December 31, 2015) of our 8.25% senior notes due 2018 issued under an Indenture dated February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15^th and August 15^th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. As a result of pushdown accounting, the effective interest rate on the 8.25% Senior Notes is approximately 5.8%.

On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness – (continued)

Derivative Instruments Premium Financing

We have historically financed premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit EPL Sub-Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit EPL Sub-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, 2015, we had no outstanding derivative instruments premium financing.

Interest Expense

For the three and six months ended December 31, 2015 and 2014, interest expense consisted of the following:


	Three Months Ended December 31,						Six Months Ended December 31,
	2015			2014			2015			2014
	(In thousands)						(In thousands)
8.25% senior notes due 2018	$	10,130		$	10,519		$	20,649		$	21,038
Amortization of fair value premium – 8.25% senior notes		(3,282	)		(2,570	)		(6,723	)		(5,104	)
Revolving credit EPL sub-facility		1,460			2,998			2,950			5,959
Promissory note payable to EGC		8,305			—			16,611			—
Derivative instruments premium financing and other		159			—			269			(45	)
	$	16,772		$	10,947		$	33,756		$	21,848

Note 7 — Derivative Financial Instruments

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use various instruments including financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. We had no derivative instruments outstanding at December 31, 2015.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7 — Derivative Financial Instruments – (continued)

The effect of derivative financial instruments on our consolidated statements of operations was as follows:


	Three Months Ended December 31,						Six Months Ended December 31,
Gain (loss) on derivative financial instruments	2015			2014			2015		2014
Cash settlements, net of purchased put premium amortization	$	1,397		$	23,091		$	2,111	$	24,903
Proceeds from monetizations		—			4,559			—		4,559
Change in fair value		(491	)		(5,388	)		1,573		14,657
Total gain on derivative financial instruments	$	906		$	22,262		$	3,684	$	44,119

Note — 8 Fair Value Measurements

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, restricted cash, accounts receivable, prepaid expenses, accounts payable, and accrued liabilities, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 8.25% Senior Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the revolving credit facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.

Our commodity derivative instruments consist of financially settled crude oil and natural gas swaps 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 7 — Derivative Financial Instruments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note — 8 Fair Value Measurements – (continued)

During the three and six months ended December 31, 2015, we did not have any transfers from or to Level 3. The following table sets forth our financial assets and liabilities that are accounted for at fair value on a recurring basis.


	December 31, 2015		June 30, 2015
	(in thousands)
Assets
Derivative financial instruments
Current	$	—	$	888
Total derivative financial instruments subject to enforceable netting agreement		—		888
Gross amounts offset in consolidated balance sheets		—		—
Net amounts presented in consolidated balance sheets	$	—	$	888
Liabilities
Derivative financial instruments
Current	$	—	$	1,057
Total derivative financial instruments subject to enforceable netting agreement		—		1,057
Gross amounts offset in consolidated balance sheets		—		—
Net amounts presented in consolidated balance sheets	$	—	$	1,057

The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments.


	December 31, 2015				June 30, 2015
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% senior notes	$	501,462	$	135,813	$	539,459	$	306,000
Revolving credit EPL sub-facility		150,000		150,000		150,000		150,000
Promissory note payable to EGC		325,000		325,000		325,000		325,000
Total	$	976,462	$	610,813	$	1,014,459	$	781,000

The 8.25% Senior Notes contain an option to redeem up to 35% of the aggregate principal amount of the notes outstanding with the net cash proceeds of certain equity offerings. This option is considered an embedded derivative and is classified as a Level 3 financial instrument for which the estimated fair value at December 31, 2015 is not material.

Note 9 — Income Taxes

We are a (U.S.) Delaware company and, as a result of the Merger, a direct subsidiary of EGC. We are 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 as they apply to our current ownership structure. ASC Topic 740, Income Taxes, provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of that group.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Income Taxes – (continued)

We allocate income tax expense/benefit and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the reporting period. We have recorded no income tax-related intercompany balances with affiliates.

We estimate the annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax/(benefit) rate is zero. Our actual effective tax/(benefit) rate for the three and six months ended December 31, 2015 was also zero. The variance from the U.S. statutory rate of 35% is primarily due to continued recorded and forecast losses that, based on present circumstances, will not result in us recording a current income tax benefit. Rather, all increases in net deferred tax assets (primarily related to net operating loss (“NOL”) carryovers net of deferred tax liability from oil and natural gas properties’ net book carrying values exceeding their corresponding tax bases) will be completely offset by increases in valuation allowances. As required by ASC Topic 740-270, Income Taxes: Interim Reporting, we forecast our tax position for the year, and may not record an additional tax benefit in an interim period unless we believe that we would be allowed to record a net deferred tax asset at the end of the year. At this time, we do not have such a belief (due to a preponderance of negative evidence as to future realizability) and accordingly reflect a current deferred tax benefit of zero. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

On June 3, 2014, we entered an intercompany services and cost allocation agreement with Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Services provided by Energy Services include management, 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 and six months ended December 31, 2015 was approximately $8.9 million and $18.2 million, respectively, of which approximately $7.5 million and $15.0 million, respectively, is included in general and administrative expense. Cost of these services for the three and six months ended December 31, 2014 was approximately $5.8 and $9.8 million, respectively, of which approximately $5.4 million and $9.1 million, respectively, is included in general and administrative expense.

On March 12, 2015, in connection with EGC’s issuance of the 11.0% Notes, we entered into the Promissory Note with a face value of $325 million. The Promissory Note bears interest at an annual rate of 10%, has a maturity date of October 9, 2018, and is secured by a second priority lien on certain of our assets that secure the obligations under the First Lien Credit Agreement. For the three and six months ended December 31, 2015, interest expense on the Promissory Note amounted to approximately $8.3 million and $16.6 million, respectively. See Note 6 — Indebtedness for more information regarding the Promissory Note.

Note 11 — Commitments and Contingencies

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

Performance Bonds. As of December 31, 2015, we had $189.7 million of performance bonds outstanding relating to assets in the Gulf of Mexico. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (“OCS”), approximately $67.2 million of our performance bonds are lease and/or area bonds issued to the BOEM that assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $122.5 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11 — Commitments and Contingencies – (continued)

bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015 and December 2015, we reached agreements with the BOEM with respect to which we provided $54.7 million and $8.9 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $67.2 million in lease and/or area bonds discussed above). On June 30, 2015, we sold the East Bay field, and as a result, the $566.5 million of requested supplemental financial assurance and/or bonding required by the BOEM in April 2015 was reduced by approximately $178 million.

In October 2015, we received information from the BOEM indicating that we could receive additional demands of supplemental financial assurance for amounts in addition to the $566.5 million initially sought by the BOEM in April 2015, primarily relating to certain properties that were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. However, we believe that a substantial portion of the additional supplemental financial assurance and/or bonding that could be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. We would expect that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding but we can provide no assurance that such cooperation by these co-lessees will occur.

Since we received the additional information from the BOEM in October 2015, we have had a series of discussions and exchanges of information with the BOEM on the long-term financial assurance plan, culminating most recently in our submittal of an updated version of the long-term financial assurance plan to the BOEM for approval on February 2, 2016. The long-term plan calls for a series of actions by us during various dates in 2016, including by June 1, 2016 and September 1, 2016, which actions are designed to address the supplemental financial assurance liabilities initially identified by the BOEM, as such liabilities are further modified by the BOEM based on information we provide and our performance under the plan. This long-term plan requires approval by the BOEM in order for us to proceed with addressing these supplemental financial assurance liabilities. While we believe that the long-term financial assurance plan is close to being approved by the BOEM, we can provide no assurance as to a certain date by which the long-term plan will be approved or that the BOEM will not have further revisions to our proposal.

If our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements. We expect that the BOEM will assess additional supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued later if those items are not addressed in our plan.

Unrelated to the BOEM’s April 2015 directive, on September 22, 2015, the BOEM issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by the BOEM with respect to supplemental bonding and, instead, broaden the self-insurance approach that would allow more operators on the OCS to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. In addition, the Draft Guidance would implement a phased-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal installments of one-third each, by no later than 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 11 — Commitments and Contingencies – (continued)

tailored plan. Furthermore, with issuance of an Advanced Notice of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters.

While the Draft Guidance, once implemented by the BOEM, would allow an increased number of operators (relative to those operators under the existing Notice to Lessees (“NTL”) regarding supplemental financial assurance and bonding) to self-insure for their decommissioning liabilities that is no more than 10% of their tangible net worth, there is no assurance that the BOEM will allow us to utilize self-insurance programs and we currently do not plan for self-insurance under the long-term financial assurance plan that we plan to submit to the BOEM.

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit EPL Sub-Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations.

We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit EPL Sub-Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended, cancelled or otherwise impose monetary penalties, and one or more of such actions could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Other. We maintain restricted escrow funds as required by certain contractual arrangements. At December 31, 2015, our restricted cash included $30 million related to the First Lien Credit Agreement and approximately $6.0 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field, which will be transferred to the buyer of our interests in that field.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.

Note 12 — Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 6 — Indebtedness, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) each of which is 100% owned by EPL (the “Guarantor Subsidiaries”), jointly and severally guaranteed the payment obligations under our 8.25% Senior Notes. The guarantees are full and unconditional, as those terms are used in Rule 3-10 of Regulation S-X, except that a Guarantor Subsidiary can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2011 Indenture. So long as other applicable provisions of the indenture are adhered to, these customary circumstances include: when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, when the requirements for legal

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EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 12 — Supplemental Condensed Consolidating Financial Information – (continued)

defeasance or covenant defeasance or to discharge the indenture have been satisfied, or when the Guarantor Subsidiary is sold or sells all of its assets. The following supplemental financial information sets forth, on a consolidating basis, the balance sheets, statements of operations and cash flow information for EPL (Parent Company Only) and for the Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries, or for any individual Guarantor Subsidiary, because management has determined that such information is not material to investors.

The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The principal eliminating entries eliminate investments in subsidiaries and intercompany balances.

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2015
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	—	$	—		$	—
Trade accounts receivable – net		42,480			—		—			42,480
Intercompany receivables		—			127,756		(127,756	)		—
Restricted cash		6,025			—		—			6,025
Prepaid expenses		2,631			—		—			2,631
Total current assets		51,136			127,756		(127,756	)		51,136
Property and equipment, net		478,477			2,949		—			481,426
Restricted cash		30,008			—		—			30,008
Investment in affiliates		130,705			—		(130,705	)		—
Other assets and debt issuance costs, net of accumulated amortization		1,036			—		—			1,036
Total assets	$	691,362		$	130,705	$	(258,461	)	$	563,606
LIABILITIES AND STOCKHOLDER’S DEFICIT
Current liabilities:
Accounts payable	$	33,076		$	—	$	—		$	33,076
Due to EGC		202,767			—		—			202,767
Intercompany payables		127,756			—		(127,756	)		—
Accrued liabilities		94,567			—		—			94,567
Asset retirement obligations		29,077			—		—			29,077
Total current liabilities		487,243			—		(127,756	)		359,487
Long-term debt		651,462			—		—			651,462
Promissory note payable to EGC		325,000			—		—			325,000
Asset retirement obligations		160,909			—		—			160,909
Total liabilities		1,624,614			—		(127,756	)		1,496,858
Stockholder’s equity (deficit):
Preferred stock		—			—		—			—
Common stock		—			—		—			—
Additional paid-in capital		1,599,341			85,479		(85,479	)		1,599,341
Retained earnings (accumulated deficit)		(2,532,593	)		45,226		(45,226	)		(2,532,593	)
Total stockholder’s equity (deficit)		(933,252	)		130,705		(130,705	)		(933,252	)
Total liabilities and stockholder’s equity (deficit)	$	691,362		$	130,705	$	(258,461	)	$	563,606

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Balance Sheet
As of June 30, 2015
(AUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	217		$	—	$	—		$	217
Trade accounts receivable – net		71,406			—		(83	)		71,323
Intercompany receivables		—			128,170		(128,170	)		—
Derivative financial instruments		888			—		—			888
Restricted cash		6,024			—		—			6,024
Prepaid expenses		1,831			—		—			1,831
Total current assets		80,366			128,170		(128,253	)		80,283
Property and equipment, net		1,412,076			2,949		—			1,415,025
Investment in affiliates		130,705			—		(130,705	)		—
Other assets and debt issuance costs, net of accumulated amortization		1,039			—		—			1,039
Total assets	$	1,624,186		$	131,119	$	(258,958	)	$	1,496,347
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	24,217		$	414	$	(83	)	$	24,548
Due to EGC		170,728			—		—			170,728
Intercompany payables		128,170			—		(128,170	)		—
Accrued liabilities		95,981			—		—			95,981
Asset retirement obligations		38,056			—		—			38,056
Derivative financial instruments		1,057			—		—			1,057
Current maturities of long-term debt		3,364			—		—			3,364
Total current liabilities		461,573			414		(128,253	)		333,734
Long-term debt		689,459			—		—			689,459
Intercompany promissory note		325,000			—		—			325,000
Asset retirement obligations		202,306			—		—			202,306
Total liabilities		1,678,338			414		(128,253	)		1,550,499
Stockholder’s equity (deficit):
Preferred stock		—			—		—			—
Common stock		—			—		—			—
Additional paid-in capital		1,599,341			85,479		(85,479	)		1,599,341
Retained earnings (accumulated deficit)		(1,653,493	)		45,226		(45,226	)		(1,653,493	)
Total stockholder’s equity (deficit)		(54,152	)		130,705		(130,705	)		(54,152	)
Total liabilities and stockholder’s equity (deficit)	$	1,624,186		$	131,119	$	(258,958	)	$	1,496,347

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2015
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues
Oil sales	$	54,408		$	—	$	—	$	54,408
Natural gas sales		8,256			—		—		8,256
Gain on derivative instruments		906			—		—		906
Total revenues		63,570			—		—		63,570
Costs and expenses
Lease operating		30,889			—		—		30,889
Transportation		664			—		—		664
Depreciation, depletion and amortization		62,333			—		—		62,333
Accretion of asset retirement obligations		6,317			—		—		6,317
Impairment of oil and natural gas properties		504,772			—		—		504,772
General and administrative		9,978			—		—		9,978
Taxes, other than on earnings		39			—		—		39
Total costs and expenses		614,992			—		—		614,992
Operating loss		(551,422	)		—		—		(551,422	)
Other income (expense):
Other income, net		2,393			—		—		2,393
Gain on early extinguishment of debt		21,269			—		—		21,269
Interest expense		(16,772	)		—		—		(16,772	)
Total other income, net		6,890			—		—		6,890
Loss before income taxes		(544,532	)		—		—		(544,532	)
Income tax expense		—			—		—		—
Net loss	$	(544,532	)	$	—	$	—	$	(544,532	)

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2014
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Revenues
Oil sales	$	109,070		$	11,758		$	—	$	120,828
Natural gas sales		12,499			49			—		12,548
Gain on derivative instruments		22,262			—			—		22,262
Total revenues		143,831			11,807			—		155,638
Costs and expenses
Lease operating		50,044			5,260			—		55,304
Transportation		1,148			1			—		1,149
Depreciation, depletion and amortization		82,382			6,165			—		88,547
Accretion of asset retirement obligations		4,910			1,188			—		6,098
Impairment of oil and natural gas properties		690,312			—			—		690,312
General and administrative		6,810			—			—		6,810
Taxes, other than on earnings		494			1,450			—		1,944
Total costs and expenses		836,100			14,064			—		850,164
Operating loss		(692,269	)		(2,257	)		—		(694,526	)
Other income (expense):
Other income, net		4			—			—		4
Interest expense		(10,947	)		—			—		(10,947	)
Income from equity investments		(1,424	)		—			1,424		—
Total other expense, net		(12,367	)		—			1,424		(10,943	)
Loss before income taxes		(704,636	)		(2,257	)		1,424		(705,469	)
Income tax benefit		(250,024	)		(833	)		—		(250,857	)
Net loss	$	(454,612	)	$	(1,424	)	$	1,424	$	(454,612	)

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2015
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues
Oil sales	$	127,780		$	—	$	—	$	127,780
Natural gas sales		20,874			—		—		20,874
Gain on derivative instruments		3,684			—		—		3,684
Total revenues		152,338			—		—		152,338
Costs and expenses
Lease operating		57,042			—		—		57,042
Transportation		1,387			—		—		1,387
Depreciation, depletion and amortization		119,993			—		—		119,993
Accretion of asset retirement obligations		13,058			—		—		13,058
Impairment of oil and natural gas properties		812,850			—		—		812,850
General and administrative		17,922			—		—		17,922
Taxes, other than on earnings		(896	)		—		—		(896	)
Total costs and expenses		1,021,356			—		—		1,021,356
Operating loss		(869,018	)		—		—		(869,018	)
Other income (expense):
Other income, net		2,405			—		—		2,405
Gain on early extinguishment of debt		21,269			—		—		21,269
Interest expense		(33,756	)		—		—		(33,756	)
Total other expense, net		(10,082	)		—		—		(10,082	)
Loss before income taxes		(879,100	)		—		—		(879,100	)
Income tax expense		—			—		—		—
Net loss	$	(879,100	)	$	—	$	—	$	(879,100	)

TABLE OF CONTENTS

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2014
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues
Oil sales	$	249,785		$	29,359	$	—		$	279,144
Natural gas sales		26,354			148		—			26,502
Gain on derivative instruments		44,119			—		—			44,119
Total revenues		320,258			29,507		—			349,765
Costs and expenses
Lease operating		102,618			8,986		—			111,604
Transportation		1,772			2		—			1,774
Depreciation, depletion and amortization		150,387			11,905		—			162,292
Accretion of asset retirement obligations		10,252			2,027		—			12,279
Impairment of oil and natural gas properties		690,312			—		—			690,312
Goodwill impairment		329,293			—		—			329,293
General and administrative		14,852			—		—			14,852
Taxes, other than on earnings		599			3,873		—			4,472
Other		21			—		—			21
Total costs and expenses		1,300,106			26,793		—			1,326,899
Operating income (loss)		(979,848	)		2,714		—			(977,134	)
Other income (expense):
Other income, net		4			—		—			4
Interest expense		(21,848	)		—		—			(21,848	)
Income from equity investments		1,711			—		(1,711	)		—
Total other expense, net		(20,133	)		—		(1,711	)		(21,844	)
Income (loss) before income taxes		(999,981	)		2,714		(1,711	)		(998,978	)
Income tax benefit		(239,013	)		1,003		—			(238,010	)
Net income (loss)	$	(760,968	)	$	1,711	$	(1,711	)	$	(760,968	)

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EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2015
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries		Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	27,463		$	—	$	—	$	27,463
Cash flows used in investing activities:
Capital expenditures		(16,122	)		—		—		(16,122	)
Net cash used in investing activities		(16,122	)		—		—		(16,122	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt		(3,395	)		—		—		(3,395	)
Cash restricted under revolving credit facility related to property sold		(30,008	)		—		—		(30,008	)
Advances from EGC		22,034			—		—		22,034
Debt issuance costs		(189	)		—		—		(189	)
Net cash used in financing activities		(11,558	)		—		—		(11,558	)
Net decrease in cash and cash equivalents		(217	)		—		—		(217	)
Cash and cash equivalents at beginning of period		217			—		—		217
Cash and cash equivalents at end of period	$	—		$	—	$	—	$	—

TABLE OF CONTENTS

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2014
(UNAUDITED)


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	93,232		$	5,669		$	—	$	98,901
Cash flows used in investing activities:
Property acquisitions		(350	)		—			—		(350	)
Capital expenditures		(233,421	)		(5,669	)		—		(239,090	)
Other property and equipment additions		(58	)		—			—		(58	)
Net cash used in investing activities		(233,829	)		(5,669	)		—		(239,498	)
Cash flows provided by financing activities:
Advances from EGC		135,480			—			—		135,480
Net cash provided by financing activities		135,480			—			—		135,480
Net decrease in cash and cash equivalents		(5,117	)		—			—		(5,117	)
Cash and cash equivalents at beginning of period		5,601			—			—		5,601
Cash and cash equivalents at end of period	$	484		$	—		$	—	$	484

TABLE OF CONTENTS

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Statements we make in this quarterly report on Form 10-Q (the “Quarterly Report”) which express a belief, expectation or intention, as well as those that are not historical fact, may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the headings “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” included in our 2015 Annual Report and elsewhere in this Quarterly Report.

Overview

EPL Oil & Gas, Inc. (“we,” “our,” “us,” “the Company” or “EPL”) was incorporated as a Delaware corporation on January 29, 1998 and is a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation and indirect wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of Bermuda (“Energy XXI”). We operate as an independent oil and natural gas exploration and production company with current operations concentrated in the U.S. Gulf of Mexico shelf (“GoM shelf”) focusing on state and federal waters offshore Louisiana, which we consider our core area.

On June 3, 2014, Energy XXI, EGC, Clyde Merger Sub, Inc., a wholly-owned subsidiary of EGC (“Merger Sub”), and EPL, completed the transactions contemplated by the Agreement and Plan of Merger, dated as of March 12, 2014 (as amended, the “Merger Agreement”), by and among Energy XXI, EGC, Merger Sub, and EPL, pursuant to which Merger Sub was merged with and into EPL with EPL continuing as the surviving corporation (the “Merger”). Pursuant to the Merger Agreement, at the effective time of the Merger, the issued and outstanding shares of EPL common stock were converted, in the aggregate, into the merger consideration consisting of approximately 65% in cash and 35% in shares of Energy XXI common stock.

As a result of the Merger, the future strategy of EPL is determined by Energy XXI’s Board of Directors. For the six months ended December 31, 2015, our capital expenditures totaled approximately $67 million. Our current capital expenditures are allocated to development activities, which are geared toward the improvement of existing production and the performance of necessary plugging, abandonment and other decommissioning activities.

Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and financial liquidity carefully. We do not expect production increases from our fiscal year 2016 capital program to entirely offset production declines, resulting in slight decreases to our production. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate. In addition, in light of current commodity prices and our leverage position, in February 2016, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and the Board, EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets. For additional detail, see “— Liquidity — Overview.” We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. If we are unable to improve our liquidity position, refinance or restructure our debt obligations or are unsuccessful in implementing such strategic alternatives, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

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We produce both oil and natural gas. Throughout this Quarterly Report, when we refer to “total production,” “total reserves,” “percentage of production,” “percentage of reserves,” or any similar term, we have converted our natural gas reserves or production into barrel of oil equivalents. For this purpose, six thousand cubic feet of natural gas is equal to one barrel of oil, which is based on the relative energy content of natural gas and oil. Natural gas liquids are aggregated with oil in this Quarterly Report.

Known Trends and Uncertainties

Commodity Price Volatility and Impact on our Results of Operations, Compliance with Debt Instruments and Liquidity. Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil and natural gas prices declined significantly during fiscal year 2015 and the decline has continued into fiscal year 2016. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from October 1, 2014 to December 31, 2015 ranged from a high of $91.01 to a low of $34.73, a decrease of 61.8%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to December 31, 2015 ranged from a high of $4.49 to a low of $1.76, a decrease of 60.8%. As of December 31, 2015, the spot market price for WTI was $37.04. Oil prices have continued to decline in 2016, with the price of WTI crude oil per barrel dropping below $27.00 in January 2016 for the first time in twelve years. The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce.

As of December 31, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility; however, based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016. There is no assurance that we will be able to resolve such non-compliance with our lenders, which may result in a default under our Revolving Credit Facility. In addition, as described in greater detail under “— Liquidity and Capital Resources — Overview,” our ability to access available borrowing capacity under our Revolving Credit EPL Sub-Facility will be limited as a result of other provisions of the Revolving Credit Facility or a reduction in our borrowing base at our next redetermination in the spring of 2016. If we experience sustained periods of low prices for oil and natural gas, it will have a further material adverse effect on our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Reserve Quantities. A prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes in our development plans. At December 31, 2015, our total proved reserves were 35.3 MMBOE. The unweighted arithmetic average first-day-of-the-month prices used to determine our reserves as of June 30, 2015 were $73.88 per barrel of oil, $31.64 per barrel for NGLs and $3.11 per MMBtu for natural gas, which is significantly higher than current forward strip prices. At NYMEX forward strip pricing as of January 29, 2016, we estimate that our total proved reserve equivalent volumes as of December 31, 2015 would have been approximately 2.2% higher compared to the results obtained using SEC pricing. Our estimated reserves as of June 30, 2015 may be further adjusted as warranted based on any changes to our long range plan, expected capital availability and drilling cost environment. The Company’s proved reserves declined significantly compared to prior years and may decline in future years. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

Ceiling Test Write-down. During the six months ended December 31, 2015, we recognized write-downs of our oil and natural gas properties totaling $812.9 million. The write-downs did not impact our cash flows from operating activities but did increase our net loss for the period and our stockholders’ deficit. Further

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ceiling test write-downs will be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows. Based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12 months ending January 31, 2016, we presently expect to incur further impairment of $75 million to $175 million in the third fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues, we will incur further impairment to our full cost pool in fiscal 2016 and beyond based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

Decreasing Service Costs. We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods.

BOEM Supplemental Financial Assurance and/or Bonding Requirements. As of December 31, 2015, we had $189.7 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal OCS, approximately $67.2 million of our performance bonds are lease and/or area bonds issued to the BOEM that the BOEM has access to and assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $122.5 million in performance bonds issued to predecessor third party assignors rather than to the BOEM, including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities.

In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015 and December 2015, we reached agreements with the BOEM with respect to which we provided $54.7 million and $8.9 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $67.2 million in lease and/or area bonds discussed above). On June 30, 2015, we sold the East Bay field, and as a result, the $566.5 million of requested supplemental bonding was reduced by approximately $178 million.

In October 2015, we received information from the BOEM indicating that we could receive additional demands of supplemental financial assurance for amounts in addition to the $566.5 million initially sought by the BOEM in April 2015, primarily relating to certain properties that are no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. However, we believe a substantial portion of the additional supplemental financial assurance and/or bonding that could be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. We would expect that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding but we can provide no assurance that such cooperation by these co-lessees will occur.

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Unrelated to the BOEM’s April 2015 directive, on September 22, 2015, the BOEM issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by BOEM with respect to supplemental bonding and, instead, broaden the self-insurance approach that would allow more operators on the OCS to seek self-insurance for a portion of their supplemental bond obligations, but only for an amount that is no more than 10% of such operators’ tangible net worth. In addition, the Draft Guidance would implement a phased-in period for establishing compliance with supplemental bonding obligations, whereby operators may seek payment of estimated costs of decommissioning obligations owed under a “tailored plan” that is approved by the BOEM and would require payment of the supplemental bonding amount in three approximately equal installments of one-third each, by no later than 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan. Furthermore, with issuance of an Advanced Notice of Proposed Rulemaking in August 2014, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters.

While the Draft Guidance, once implemented by the BOEM, would allow an increased number of operators (relative to those operators under the existing NTL regarding supplemental financial assurance and bonding) to self-insure for their decommissioning liabilities that is no more than 10% of their tangible net worth, there is no assurance that the BOEM will allow us to utilize self-insurance programs and we currently do not plan for self-insurance under the long-term financial assurance plan that we plan to submit to the BOEM.

We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit EPL Sub-Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended, cancelled or otherwise impose monetary penalties, and one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Oil Spill Response Plan. We maintain a Regional Oil Spill Response Plan (the “OSRP”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). The OSRP is reviewed at least annually, and updated as necessary, which updates also require BSEE approval. The OSRP specifications are consistent with the requirements set forth by the BSEE. Additionally, the OSRP is tested and drills are conducted annually at all levels of the Company.

We have contracted with a spill response management consultant to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing

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and pipeline companies operating in the Gulf of Mexico that has the appropriate equipment, including aircraft dispersant capabilities through its contract with Airborne Support Inc. and access to appropriate personnel to simultaneously respond to multiple spills. In the event of a spill, CGA mobilizes appropriate equipment and personnel to CGA members.

Hurricanes. Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.

Results of Operations

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

Our consolidated net loss for the three months ended December 31, 2015 was $544.5 million as compared to $454.6 million for the three months ended December 31, 2014. The increase in the net loss was primarily due to no income tax benefit and lower revenues due to lower oil and natural gas sales prices in the second quarter of fiscal 2015, partially offset by lower impairment of oil and natural gas properties.

Revenues


	Three Months Ended December 31,				Decrease			Percent Decrease
	2015		2014		Decrease			Percent Decrease
			(In thousands)
Oil	$	54,408	$	120,828	$	(66,420	)		(55.0	)%
Natural gas		8,256		12,548		(4,292	)		(34.2	)%
Gain on derivative financial instruments		906		22,262		(21,356	)		(95.9	)%
Total Revenues	$	63,570	$	155,638	$	(92,068	)		(59.2	)%

Our consolidated revenues decreased $92.1 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity sales prices and lower gain on derivative financial instruments. Revenue variances related to commodity prices, sales volumes and hedging activities are presented in the following table and described below.

Price and Volume Variances


	Three Months Ended December 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2015			2014			Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
													(In thousands)
Price Variance
Oil sales prices (per Bbl)	$	38.18		$	71.12		$	(32.94	)		(46.3	)%	$	(55,958	)
Natural gas sales prices (per Mcf)		1.85			3.52			(1.67	)		(47.4	)%		(5,943	)
Gain on derivative financial instruments (per BOE)		0.42			9.71			(9.29	)		(95.7	)%		(21,356	)
Total price variance														(83,257	)
Volume Variance
Oil sales volumes (MBbls)		1,425			1,699			(274	)		(16.1	)%		(10,462	)
Natural gas sales volumes (MMcf)		4,455			3,564			891			25.0	%		1,651
BOE sales volumes (MBOE)		2,167			2,293			(126	)		(5.5	)%
Percent of BOE from oil		66	%		74	%
Total volume variance														(8,811	)
Total price and volume variance													$	(92,068	)

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Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $83.3 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $32.94 per barrel in the second quarter of fiscal 2016, resulting in lower revenues of $56.0 million. Average natural gas prices decreased $1.67 per Mcf in the second quarter of fiscal 2016 compared to the second quarter of fiscal 2015, resulting in lower revenues of $5.9 million. For the second quarter of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $0.42 per BOE compared to a gain of $9.71 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $21.4 million. The gain on derivatives for the three months ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $16.28 per barrel of oil.

Commodity prices are affected by many factors that are outside of our control, and we cannot accurately predict future commodity prices. Depressed commodity prices over an extended period of time will result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. As a result of our high level of indebtedness and commodity prices, we have significantly reduced our planned capital spending, and such curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes decreased 3.0 MBbls per day in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $10.5 million. Natural gas sales volumes increased by 9.7 MMcf per day for the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in higher revenues of $1.7 million. Overall sales volumes decreased because of natural well declines, reduced drilling activity resulting in less new production, and irregular downtime due to third party pipelines. In the low commodity price environment, we expect to see further production declines due to natural declines and limited activity in the fields.

Costs and Expenses and Other (Income) Expense


	Three Months Ended December 31,											Increase (Decrease) Total $
	2015						2014
	Total $			Per BOE			Total $			Per BOE
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense	$	30,889		$	14.25		$	55,304		$	24.12	$	(24,415	)
Transportation		664			0.31			1,149			0.50		(485	)
Depreciation, depletion and amortization		62,333			28.76			88,547			38.62		(26,214	)
Accretion of asset retirement obligations		6,317			2.92			6,098			2.66		219
Impairment of oil and natural gas properties		504,772			232.94			690,312			301.05		(185,540	)
General and administrative		9,978			4.60			6,810			2.97		3,168
Taxes, other than on earnings		39			0.02			1,944			0.85		(1,905	)
Total costs and expenses	$	614,992		$	283.80		$	850,164		$	370.77	$	(235,172	)
Other (income) expense
Other income, net	$	(2,393	)	$	(1.10	)	$	(4	)	$	—	$	(2,389	)
Gain on early extinguishment of debt		(21,269	)		(9.81	)		—			—		(21,269	)
Interest expense		16,772			7.74			10,947			4.77		5,825
Total other (income) expense, net	$	(6,890	)	$	(3.17	)	$	10,943		$	4.77	$	(17,833	)

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Costs and expenses decreased $235.2 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to the decrease in impairment of oil and gas properties, depreciation, depletion and amortization (“DD&A”) and lease operating expense and other factors discussed further below.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling tests, we recognized ceiling test impairments of our oil and natural gas properties of $504.8 million for the quarter ended December 31, 2015 and $690.3 million for the quarter ended December 31, 2014.

Lease operating expense decreased $24.4 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. This decrease was primarily due to lower direct lease operating expenses stemming from declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services. Lease operating expense per BOE declined from $24.12 for the quarter ended December 31, 2014 to $14.25 for the quarter ended December 31, 2015.

DD&A expense decreased $26.2 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $9.86. The decrease in the DD&A rate in the second quarter of fiscal 2016 was primarily due to the reduction in our full cost pool due to the impairments of our oil and natural gas properties in prior quarterly periods of fiscal year 2015 and 2016 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

General and administrative expense increased $3.2 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to an increase in the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate.

Interest expense increased approximately $5.8 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to interest on the promissory note payable to EGC.

During the three months ended December 31, 2015, we repurchased $29.8 million of our 8.25% Senior Notes in open market transactions at a total cost of approximately $10.0 million, and we recorded a gain on the repurchases totalling approximately $21.3 million, including the amount of associated unamortized premium.

Income Taxes

The income tax expense for the second quarter of fiscal 2016 is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. We recorded no income tax expense (benefit) in the second quarter of fiscal 2016 compared to income tax benefit of $250.9 million in the second quarter of fiscal 2015. For the second quarter of fiscal 2015, our effective income tax rate was 35.6%. The decrease in the tax rate is primarily due to the book loss for the quarter, the forecast book loss for the year and our inability to currently record any additional net deferred tax assets due to a preponderance of negative evidence as to future realizability of these deferred tax assets. Please see Note 9 — Income Taxes in Notes to Consolidated Financial Statements in this Quarterly Report.

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Six Months Ended December 31, 2015 Compared to Six Months Ended December 31, 2014

Our consolidated net loss for the six months ended December 31, 2015 was $879.1 million as compared to $761.0 million for the six months ended December 31, 2014. The increase in the net loss was primarily due to lower revenues due to lower oil and natural gas sales prices, higher impairment of oil and natural gas properties, and no income tax benefit in the fiscal 2016 period.

Revenues


	Six Months Ended December 31,				Decrease			Percent Decrease
	2015		2014		Decrease			Percent Decrease
			(In thousands)
Oil	$	127,780	$	279,144	$	(151,364	)		(54.2	)%
Natural gas		20,874		26,502		(5,628	)		(21.2	)%
Gain on derivative financial instruments		3,684		44,119		(40,435	)		(91.6	)%
Total Revenues	$	152,338	$	349,765	$	(197,427	)		(56.4	)%

Our consolidated revenues decreased $197.4 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity sales prices and lower gain on derivative financial instruments. Revenue variances related to commodity prices, sales volumes and hedging activities are presented in the following table and described below.

Price and Volume Variances


	Six Months Ended December 31,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	2015			2014			Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
													(In thousands)
Price Variance
Oil sales prices (per Bbl)	$	41.69		$	83.05		$	(41.36	)		(49.8	)%	$	(139,024	)
Natural gas sales prices (per Mcf)		2.26			3.72			(1.46	)		(39.1	)%		(10,372	)
Gain on derivative financial instruments (per BOE)		0.80			9.70			(8.90	)		(91.7	)%		(40,435	)
Total price variance														(189,831	)
Volume Variance
Oil sales volumes (MBbls)		3,065			3,361			(296	)		(8.8	)%		(12,340	)
Natural gas sales volumes (MMcf)		9,223			7,127			2,096			29.4	%		4,744
BOE sales volumes (MBOE)		4,602			4,549			53			1.2	%
Percent of BOE from oil		67	%		74	%
Total volume variance														(7,596	)
Total price and volume variance													$	(197,427	)

Price Variances

Lower commodity prices decreased revenues by $189.8 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $41.36 per barrel in the first six months of fiscal 2016, resulting in lower revenues of $139.0 million. Average natural gas prices decreased $1.46 per Mcf in the first six months of fiscal 2016 compared to the first six months of fiscal 2015, resulting in lower revenues of $10.4 million. For the first six months of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $0.80 per BOE compared to a gain of $9.70 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $40.4 million. The gain on derivatives for the six months ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $8.77 per barrel of oil.

Volume Variances

Oil sales volumes decreased 1.6 MBbls per day in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $12.3 million. Natural gas sales volumes

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were higher in the first six months of fiscal 2016, increasing 11.4 MMcf per day for the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in higher revenues of $4.7 million.

Costs and Expenses and Other (Income) Expense


	Six Months Ended December 31,											Increase (Decrease) Total $
	2015						2014
	Total $			Per BOE			Total $			Per BOE
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense	$	57,042		$	12.40		$	111,604		$	24.53	$	(54,562	)
Transportation		1,387			0.30			1,774			0.39		(387	)
Depreciation, depletion and amortization		119,993			26.07			162,292			35.68		(42,299	)
Accretion of asset retirement obligations		13,058			2.84			12,279			2.70		779
Impairment of oil and natural gas properties		812,850			176.63			690,312			151.75		122,538
Goodwill impairment		—			—			329,293			72.39		(329,293	)
General and administrative		17,922			3.89			14,852			3.26		3,070
Taxes, other than on earnings		(896	)		(0.19	)		4,472			0.98		(5,368	)
Other		—			—			21			—		(21	)
Total costs and expenses	$	1,021,356		$	221.94		$	1,326,899		$	291.68	$	(305,543	)
Other (income) expense
Other income, net	$	(2,405	)	$	(0.52	)	$	(4	)	$	—	$	(2,401	)
Gain on early extinguishment of debt		(21,269	)		(4.62	)		—			—		(21,269	)
Interest expense		33,756			7.34			21,848			4.80		11,908
Total other expense, net	$	10,082		$	2.20		$	21,844		$	4.80	$	(11,762	)

Costs and expenses decreased $305.5 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to decreases in goodwill impairment, lease operating expense and DD&A, partially offset by an increase in impairment of oil and natural gas properties. Please see further discussion below.

As a result of our ceiling tests, we recognized ceiling test impairments of our oil and natural gas properties totaling $812.9 million for the six months ended December 31, 2015 and $690.3 million for the six months ended December 31, 2014.

During the six months ended December 31, 2014, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at September 30, 2014. At September 30, 2014, we performed a goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since June 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital, both of 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 was no remaining implied fair value attributable to goodwill at September 30, 2014.

Lease operating expense decreased $54.6 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year. This decrease was primarily due to lower direct lease operating expenses stemming from declining service costs resulting from the decline in commodity prices and decrease in demand for oil field services. Lease operating expense per BOE declined from $24.53 for the six months ended December 31, 2014 to $12.40 for the six months ended December 31, 2015.

DD&A expense decreased $42.3 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $9.61. The decrease

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in the DD&A rate in the first six months of fiscal 2016 was primarily due to the reduction in our full cost pool due to the impairments of our oil and natural gas properties in prior quarterly periods of fiscal year 2015 and 2016 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

General and administrative expense increased $3.1 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to an increase in the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate lower capitalized amounts.

Interest expense increased approximately $11.9 million in the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to interest on the promissory note payable to EGC.

During the six months ended December 31, 2015, we repurchased $29.8 million of our 8.25% Senior Notes in open market transactions at a total cost of approximately $10.0 million, and we recorded a gain on the repurchases totalling approximately $21.3 million, including the amount of associated unamortized premium.

Income Taxes

The income tax expense for the first six months of fiscal 2016 is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. We recorded no income tax expense (benefit) in the first six months of fiscal 2016 compared to income tax benefit of $238.0 million in the first six months of fiscal 2015. For the first six months of fiscal 2015, our effective income tax rate was 23.8%. The decrease in the tax rate is primarily due to the book loss for the period, the forecast book loss for the year and our inability to currently record any additional net deferred tax assets due to a preponderance of negative evidence as to future realizability of these deferred tax assets. See Note 9 — Income Taxes in Notes to Consolidated Financial Statements in this Quarterly Report.

Liquidity and Capital Resources

Overview

Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. Future cash flows are subject to a number of variables and are highly dependent on the prices we receive for oil and natural gas production. Oil prices and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As of December 31, 2015, we had $150 million in borrowings outstanding under the Revolving Credit Facility, to which we are party with EGC, and we were in compliance with our financial covenants; however, based on current market conditions and depressed commodity prices, if Energy XXI is unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016. In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in the Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

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with our lenders on any such amendment or waiver. Absent success in these pursuits, a resultant breach 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. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI’s 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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

EGC may face other impediments to accessing available borrowing capacity under the Revolving Credit Facility. Borrowings under the First Lien Credit Agreement are limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we, EGC and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base of $150 million for EPL, although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. As of December 31, 2015, we have fully utilized amounts available under our Revolving Credit EPL Sub-Facility. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit EPL Sub-Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness in excess of any reduced borrowing base.

In addition, in response to commodity price declines, our fiscal year 2016 capital budget was substantially reduced compared to actual capital expenditures in fiscal year 2015. The curtailment of the development of our properties will eventually lead to a decline in our production and reserves. In addition, due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

We may experience a further strain on our liquidity if the BOEM requires us to provide additional bonding as a means to assure our decommissioning obligations, or if the surety companies providing such bonds on our behalf require us to provide additional cash collateral for such bonds. Any further expense in providing additional bonds or restrictions on our cash to collateralize existing bonds or new bonds would further reduce our liquidity.

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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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

As described below under “— Our Indebtedness and Available Credit,” we had total indebtedness of $976.5 million as of December 31, 2015, and taking into account the bond repurchases completed subsequent to December 31, 2015 of approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes at a total price of approximately $11.4 million, including accrued interest of $10.4 million, we had total indebtedness of $697.1 million as of February 15, 2016. All of our outstanding indebtedness will mature within the next three years. In addition, the Revolving Credit Facility is scheduled to mature on April 9, 2018; however, the maturity of the Revolving Credit Facility will accelerate if EGC’s 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. All of the factors described above have placed considerable pressure on our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities, continue our development activities to maintain and grow reserves and our ability to refinance our debt as it becomes due. As a result of the commodity price decline and the Company’s substantial debt burden, absent a material improvement in oil and gas prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, the Company believes forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months. This raises substantial doubt regarding the Company’s ability to continue as a going concern.

In February 2016, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and Board, EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Energy XXI is also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows.

As a result of the commodity price decline, we will continue to evaluate our ability to make the debt payments in light of our liquidity constraints, but if we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we will have to take certain actions described in greater detail elsewhere in this Quarterly Report and in our 2015 Annual Report in “Risk Factors — We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.”

On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing our outstanding 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI are working with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

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immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

Our Indebtedness and Available Credit

Revolving Credit EPL Sub-Facility. The First Lien Credit Agreement, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base under the Revolving Credit EPL Sub-Facility, although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. As of December 31, 2015, we had fully utilized amounts available under our Revolving Credit EPL Sub-Facility. The maturity date of the First Lien Credit Agreement is April 9, 2018, provided that certain conditions are met; however, the maturity of the Revolving Credit Facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. The Revolving Credit Facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 5% of the overall commitment amount.

On November 30, 2015, EGC and EPL entered into the Twelfth Amendment to the First Lien Credit Agreement, under which the following changes became effective:

•

Modification of triggers that require EPL and its subsidiaries to provide guarantees of the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees. Under such modifications, such guarantees and security will be required upon the earlier of EPL’s retirement of its obligations in respect of the 8.25% Senior Notes and amendments to covenant restrictions under such notes that eliminate restrictions on the ability of EPL and its subsidiaries to guarantee the indebtedness of EGC and its subsidiaries and grant liens on the assets of EPL and its subsidiaries to secure such guarantees (even if such notes have not been refinanced or defeased).

•

Suspending the maximum net secured leverage ratio covenant with respect to EPL and its subsidiaries to begin on the fiscal quarter ending March 31, 2017 rather than March 31, 2015.

•

As amended, the First Lien Credit Agreement requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenants on a consolidated basis: (a) a minimum current ratio of no less than 1.0 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 as of the end of the fiscal quarter ended December 31, 2015, and increasing to 4.75 to 1.0 starting March 31, 2016, and to 5.25 to 1.00 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. If the 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a

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consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a minimum current ratio of no less than 1.0 to 1.0.

Since required lender consent to the specific terms of the transaction with respect to the sale of the East Bay field had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default.

8.25% Senior Notes. The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount issued under the 2011 Indenture. Subsequent to December 31, 2015, we repurchased approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes in open market transactions at a total price of approximately $11.4 million, including accrued interest of $10.4 million. The 8.25% Senior Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15^th and August 15^th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. As of December 31, 2015, we were in compliance with all of the covenants under the 2011 Indenture; however, based on current market conditions and depressed commodity prices, if Energy XXI is unable to execute on one of the strategic alternatives discussed above and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016.

Promissory Note. On March 12, 2015, in connection with EGC’s issuance of the 11.0% Notes, we entered into the $325.0 million secured second lien Promissory Note between us, as the maker, and EGC, as the payee. The Promissory Note bears interest at an annual rate of 10%, has a maturity date of October 9, 2018, and is secured by a second priority lien on certain of our assets that secure the obligations under the First Lien Credit Agreement.

For more information regarding our outstanding indebtedness, see Note 6 — Indebtedness in the Notes to Consolidated Financial Statements contained in this Quarterly Report.

BOEM Bonding Requirements

The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our Revolving Credit Facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. For more information about BOEM’s supplement bonding requirements, see “— Known Trends and Uncertainties — BOEM Supplemental Financial Assurance and/or Bonding Requirements.”

Capital Expenditures

For the six months ended December 31, 2015, our capital expenditures totaled approximately $67 million including expenditures for plugging, abandonment and other decommissioning activities. Our current capital expenditures are allocated to development activities, which are geared toward the improvement of existing production and the performance of necessary plugging, abandonment and other decommissioning activities. We intend to fund our capital expenditures and contractual commitments with cash flows from operating

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activities and borrowings and equity investments from EGC. If oil and natural gas prices remain at current levels or continue to decline and our cash flows from operating activities and availability of funding from EGC are not sufficient to fund our capital program, we will further reduce our capital spending or otherwise fund our capital needs with proceeds from the sale of non-core assets. There is no guarantee that we can access debt and equity capital markets or sell non-core assets at attractive terms. Our capital expenditures and the scope of our drilling activities for fiscal year 2016 may change as a result of several factors, including, but not limited to, changes in oil and natural gas sales prices, costs of drilling and completion operations and drilling results and available funding from EGC.

Disposition

On June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration was payable in two installments with $5 million received at closing and the remainder received during the quarter ended December 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field.

We may decide to divest of certain non-core assets from time to time. There can be no assurance any such potential transactions will prove successful. We cannot provide any assurance that we will be able to sell these assets on satisfactory terms, if at all.

Cash Flows

The following table sets forth selected historical information from our statements of cash flows:


	Six Months Ended December 31,
	2015			2014
	(In thousands)
Net cash provided by operating activities	$	27,463		$	98,901
Net cash used in investing activities		(16,122	)		(239,498	)
Net cash provided by (used in) financing activities		(11,558	)		135,480

The decrease in our net cash provided by operating activities for the first six months of fiscal 2016 as compared to the same period in the prior fiscal year primarily reflects decreases in revenues due to lower oil and natural gas prices.

Net cash used in investing activities decreased for the first six months of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to the reduction in cash used for capital expenditures.

Net cash used in financing activities for the first six months of fiscal 2016 primarily reflects $30.0 million in restricted cash related to the Revolving Credit Facility and $3.4 million in payments on derivative instruments premium financing, partially offset by $22.0 million in advances from EGC. Net cash provided by financing activities for the first six months of fiscal year 2015 reflects $135.5 million in advances from EGC.

We have not paid any cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including the 2011 Indenture governing the 8.25% Senior Notes, place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

Contractual Obligations

Our contractual obligations at December 31, 2015 did not change materially from those disclosed in Item 7 of our 2015 Annual Report, other than as disclosed in Note 6 — Indebtedness and Note 5 — Asset Retirement Obligations of Notes to Consolidated Financial Statements in this Quarterly Report.

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Critical Accounting Policies

Our significant accounting policies are summarized in Note 1 — Organization and Summary of Significant Accounting Policies of Notes to Consolidated Financial Statements included in our 2015 Annual Report.

Recent Accounting Pronouncements

For information regarding new accounting pronouncements, see the information in Note 1 — Organization and Summary of Significant Accounting Policies — Recent Accounting Pronouncements of Notes to Consolidated Financial Statements in this Quarterly Report.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

General

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our 2015 Annual Report.

We are exposed to a variety of market risks including commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at December 31, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which are volatile and may fluctuate widely. Oil and natural gas price declines such as the recent declines adversely affect our revenues, cash flows and profitability. The Company continues to incur significant losses from operations. As a result of the depressed pricing environment, further declines could impact the extent to which we develop portions of our proved and unproved oil and natural gas properties, and could possibly include temporarily shutting in certain wells that are uneconomic to produce. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operations and the value of our assets.

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. We have incurred debt under the borrowing base of our Revolving Credit EPL Sub-Facility. This borrowing base is subject to periodic redetermination based in part on changing expectations of future prices. Recently, commodity prices have deteriorated materially. If we experience the continuation of low oil and gas prices, or if they decline even further, we anticipate that our existing Revolving Credit EPL Sub-Facility borrowing base and commitment amounts will likely be reduced in the

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spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness under the Revolving Credit Facility in excess of any reduced borrowing base. The energy markets have historically been very volatile, and there can be no assurance that crude oil and natural gas prices will improve.

Historically, we have utilized commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. Any gains or losses resulting from the change in fair value from hedging transactions and from the settlement of hedging contracts are recorded in earnings as a component of revenues. At December 31, 2015, we had no derivative instruments outstanding.

For a complete discussion of our derivative financial instruments, see Note 7 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our Revolving Credit EPL Sub-Facility. As of December 31, 2015, total debt included $150.0 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 15% of our total debt outstanding as of December 31, 2015. A 10% change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $16,106. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.

Item 4.

CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on this evaluation and as a result of a material weakness identified during preparation of the Company’s financial statements for the fiscal year ended June 30, 2015 which has not been fully remediated, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of the end of the period covered by this Quarterly Report.

Changes in Internal Control over Financial Reporting

Energy XXI’s board of directors recently implemented additional controls and procedures in response to a material weakness in its control environment identified during the preparation of its financial statements for the fiscal year ended June 30, 2015, including, but not limited to, strengthening Energy XXI’s vendor procurement procedures to address any potential conflicts of interest that could arise between Energy XXI and any of its vendors; amending Energy XXI’s Code of Business Conduct and Ethics to, among other things, include explicit prohibitions and heightened disclosures addressing activities or personal interests that create or appear to create a conflict between personal interests and the interests of Energy XXI and implementing a new insider trading policy. The Company is also implementing an enhanced comprehensive training program on these new procedures and policies.

Other than changes related to the items noted above, there was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS.

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 financial position or results of operations.

Item 1A.

RISK FACTORS.

Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in Energy XXI’s common stock, please refer to the section entitled “Item 1A. — Risk Factors” in our 2015 Annual Report. There have been no material changes in the risk factors set forth in our 2015 Annual Report other than those set forth below.

Current commodity prices impact our ability to comply with debt covenants in our Revolving Credit Facility.

We depend on our Revolving Credit Facility for a portion of our future capital needs. Our Revolving Credit Facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. Due to the continued decreases in commodity prices, the Company continues to incur significant losses and negative cash flows from operating activities. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

We also are required to comply with certain debt covenants and ratios. Our ability to comply with these restrictions and covenants in the future will be affected by the levels of cash flow from our operating activities and events or circumstances beyond our control. Our cash flow is highly dependent on the prices we receive for oil and natural gas, which have declined significantly in the quarter ended December 31, 2015 and further in the current quarter. As of December 31, 2015, we were in compliance with our debt covenants; however, based on current market conditions and depressed commodity prices, if we are unable to adequately address liquidity concerns through one of the strategic alternatives described below, we will not be in compliance with the consolidated net secured leverage ratio covenant under our Revolving Credit Facility for the quarter ending March 31, 2016. Energy XXI is evaluating various alternatives with respect to the Revolving Credit Facility, but there is no certainty that it will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver.

In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in the Revolving Credit Facility. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation.

Energy XXI has engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and Board, EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure you

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that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all.

Absent success in these pursuits, a resultant breach under the Revolving Credit Facility from covenant non-compliance or our inability to deliver the required solvency representations would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration would cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI’s 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 will not have sufficient liquidity to repay all of our outstanding indebtedness. As a result, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our financial statements.

We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

During the second half of 2014 and into 2015, NYMEX-WTI oil prices fell from in excess of $100 per Bbl to below $50 per Bbl, the lowest price since 2009. Over the same period, Henry Hub spot prices for natural gas fell from in excess of $3.00 per MMBtu to below $2.00 per MMBtu. Oil prices have continued to decline in the first calendar quarter of 2016, with the price of WTI crude oil per barrel dropping below $27.00 in January 2016 for the first time in twelve years. These events have adversely impacted our available liquidity.

As of January 31, 2016, EGC had cash and cash equivalents of approximately $269 million and approximately $122 million of available borrowing capacity under our Revolving Credit Facility, which has a borrowing base of $500 million. As discussed above, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in the Revolving Credit Facility. As discussed above, absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we will not be in compliance with the consolidated net secured leverage ratio under the Revolving Credit Facility for the quarter ending March 31, 2016. In addition, the current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required solvency representation. Finally, continuation of hydrocarbon prices at current levels increase the likelihood that our borrowing base will be reduced as part of our next borrowing base redetermination scheduled for the spring of 2016. Given that our $150 million Revolving Credit EPL Sub-Facility is fully drawn, we will likely be required to repay amounts under the Revolving Credit Facility to the extent our borrowings under the Revolving Credit Facility exceed the redetermined borrowing base. If low prices continue and we are unable to achieve a restructuring of our debt obligations or other improvement in liquidity, all of these factors will limit EGC’s ability to access available borrowing capacity under the Revolving Credit Facility to provide funds to us and forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months.

On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 16, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

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indebtedness, draw on the Revolving Credit EPL Sub-Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

As discussed in the risk factor above, Energy XXI is currently evaluating strategic alternatives to address the Company’s liquidity issues and high debt levels, but we cannot assure you that any of these strategies will yield sufficient funds to meet our working capital or other liquidity needs, including for payments of interest and principal on our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations. As a result, we may seek protection of the United States Bankruptcy Court (the “Bankruptcy Court”) to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

We may seek the protection of the Bankruptcy Court, which may harm our business and place equity holders at significant risk of losing all of their interests in the Company.

We are in the process of analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives through a private restructuring. However, a filing under Chapter 11 of the U.S. Bankruptcy Code may be unavoidable. Seeking Bankruptcy Court protection could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as a proceeding related to a Chapter 11 proceeding continues, our senior management would be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. Bankruptcy Court protection also might make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer a proceeding related to a Chapter 11 proceeding continues, the more likely it is that our customers and suppliers would lose confidence in our ability to reorganize our businesses successfully and would seek to establish alternative commercial relationships.

Additionally, we have a significant amount of secured indebtedness that is senior to our unsecured indebtedness and a significant amount of total indebtedness that is senior to our existing preferred stock and common stock in our capital structure. As a result, we believe that seeking Bankruptcy Court protection under a Chapter 11 proceeding could result in a limited recovery for unsecured noteholders, if any, and place equity holders at significant risk of losing all of their interests in the Company.

If we are unable to spend the capital necessary to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves, which could adversely affect our results of operations.

At June 30, 2015, approximately 24% of our total estimated proved reserves were undeveloped and may not be ultimately developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove to be accurate. Our reserve report at June 30, 2015 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $203 million. We cannot be certain the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. If we are unable to spend the capital necessary to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any proved undeveloped reserves not developed within this five-year time frame.

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Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. A removal of such reserves will adversely affect our results of operations. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations.

To cover the costs for various obligations of lessees on the OCS, including costs for such decommissioning obligations as the plugging of wells, the removal of platforms and other facilities, the decommissioning of pipelines and the clearing of the seafloor of obstructions typically performed at the end of production, the BOEM generally requires that the lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Failure to post the requisite bonds or otherwise satisfy the BOEM’s security requirements could have a materially adverse effect on our ability to operate in the U.S. Gulf of Mexico.

Because we are not exempt from the BOEM’s supplemental bonding requirements, we engage a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral at the outset of the agreement or subsequently on demand, the amount of which typically may be increased at the surety companies’ discretion. Given current commodity prices’ effect on our creditworthiness and the unwillingness of the surety companies to post bonds without the requisite collateral, we cannot assure that we will always be able to satisfy the demands for additional collateral for current bonds or comply with new supplemental bonding requirements. If we fail to do so, we may be in default under our agreements with the surety companies, which in turn could cause a cross-default under our Revolving Credit Facility and potentially our indentures.

We may be required to provide additional letters of credit to support the additional collateral or bonding requirements requested by the BOEM or the surety companies. Such letters of credit would likely be issued under our Revolving Credit Facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases given these new expenses, and if we are unable to obtain the additional required bonds or the increased amount of required collateral as requested, the BOEM may require any or all of our operations on federal leases to be suspended or cancelled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

If the trading price of Energy XXI’s common stock fails to comply with the continued listing requirements of NASDAQ, our liquidity could be materially and adversely affected.

Beginning on January 11, 2016, Energy XXI’s common stock has generally traded on NASDAQ at less than $1.00 per share. Due to certain NASDAQ requirements, there is no assurance that the price of Energy XXI’s common stock will comply with the requirements for continued listing of its shares on NASDAQ. A delisting of Energy XXI’s common stock could constitute a “fundamental change” under the terms of its $400 million aggregate principal amount of 3.0% Senior Convertible Notes due 2018. If such a fundamental change occurs at any time prior to the maturity of the 3.0% Senior Convertible Notes, each holder of such notes shall have the right to require Energy XXI to repurchase all or part of such holder’s 3.0% Senior Convertible Notes in accordance with the terms of the 3.0% Senior Convertible Notes. We cannot assure that Energy XXI would have adequate liquidity to fund such a repurchase given its severe liquidity constraints. Such acceleration would cause a cross-default or cross-acceleration of all of Energy XXI’s other outstanding indebtedness, including our 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

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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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

New regulatory initiatives imposing more stringent requirements regarding the emission of pollutants, including greenhouse gases, could cause us to incur increased capital expenditures and operating costs, which could be significant.

The federal Clean Air Act and comparable state laws, regulate emissions of various air pollutants through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to result in the emission of new or increased existing air pollutants, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. In a second example, in October 2015, the EPA issued a final rule under the federal Clean Air Act, lowering the National Ambient Air Quality Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country will use to achieve its greenhouse gas emissions targets. Although it is not possible at this time to predict how new methane or ozone restrictions would impact our business or how or when the United State might impose restrictions on greenhouse gases as a result of the international agreement agreed to in Paris but any new legal requirements that impose more stringent requirements on the emission of pollutants, including greenhouse gases, from our operations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, demand for our services, results of operations, and cash flows.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

Item 3.

DEFAULTS UPON SENIOR SECURITIES.

None

Item 4.

MINE SAFETY DISCLOSURES.

Not applicable

Item 5.

OTHER INFORMATION.

None

Item 6.

EXHIBITS.

The exhibits listed on the accompanying Exhibit Index are filed or incorporated by reference as part of this Quarterly Report, and such Exhibit Index is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EPL Oil & Gas, Inc.

Date: February 16, 2016

By:

/s/ Rick D. Fox

Rick D. Fox
Chief Financial Officer
(Principal Financial Officer and Principal
Accounting Officer)

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INDEX TO EXHIBITS


Exhibit Number	Exhibit Description	Incorporated by Reference Form	SEC File Number	Exhibit	Filing Date	Filed/ Furnished Herewith
2.1	Purchase and Sale Agreement dated June 3, 2014 by and between Energy XXI GOM, LLC, as seller, and EPL Oil & Gas, Inc., as purchaser	8-K	001-16179	2.1	9/3/2014
3.1	Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009	8-A/A	001-16179	3.1	9/21/2009
3.2	Third Amended and Restated Bylaws of EPL Oil & Gas, Inc.	8-K	001-16179	3.1	10/18/2012
3.3	Fourth Amended and Restated Bylaws of EPL Oil & Gas, Inc.	8-K	001-16179	3.2	6/3/2014
3.4	Certificate of Ownership and Merger filed with the Secretary of State of the State of Delaware, which became effective by its terms on September 1, 2012	8-K	001-16179	3.1	9/5/2012
3.5	Composite copy of the Third Amended and Restated Bylaws of EPL Oil & Gas, Inc., reflecting all amendments through March 11, 2014, the effective date of the Amendment to the Third Amended and Restated Bylaws	10-Q	001-16179	3.1	5/8/2014
3.6	Amended and Restated Certificate of Incorporation of EPL Oil & Gas, Inc., adopted June 3, 2014	8-K	001-16179	3.1	6/3/2014
10.1	Twelfth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of November 30, 2015	8-K	001-16179	10.1	11/30/2015
31.1	Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended					X
31.2	Certification of Principal Financial Officer of EPL Oil & Gas, Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended					X
32.1	Section 1350 Certification of Principal Executive Officer and Chief Financial Officer of EPL Oil & Gas, Inc. pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					X

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Exhibit
Number

Exhibit Description

Incorporated
by Reference
Form

SEC File
Number

Exhibit

Filing Date

Filed/
Furnished
Herewith

101.INS*

XBRL Instance Document

101.SCH*

XBRL Taxonomy Extension Schema Document

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

Incorporated herein by reference as indicated.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

Form 10-Q

EPL Oil & Gas, Inc.

(713) 351-3000

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

PART I — FINANCIAL INFORMATION

EPL OIL & GAS, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In thousands, except share data)

EPL OIL & GAS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (In thousands)

EPL OIL & GAS, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)(In thousands)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Organization and Summary of Significant Accounting Policies

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Organization and Summary of Significant Accounting Policies – (continued)

Note 2 — Liquidity and Capital Resources

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 2 — Liquidity and Capital Resources – (continued)

Note 3 — Pushdown Accounting and Goodwill

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 3 — Pushdown Accounting and Goodwill – (continued)

Note 4 — Property and Equipment

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 4 — Property and Equipment – (continued)

Note 5 — Asset Retirement Obligations

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 6 — Indebtedness

Revolving Credit EPL Sub-Facility

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 6 — Indebtedness – (continued)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 6 — Indebtedness – (continued)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 6 — Indebtedness – (continued)

Promissory Note

8.25% Senior Notes due 2018

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 6 — Indebtedness – (continued)

Derivative Instruments Premium Financing

Interest Expense

Note 7 — Derivative Financial Instruments

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 7 — Derivative Financial Instruments – (continued)

Note — 8 Fair Value Measurements

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note — 8 Fair Value Measurements – (continued)

Note 9 — Income Taxes

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 9 — Income Taxes – (continued)

Note 10 — Related Party Transactions

Note 11 — Commitments and Contingencies

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 11 — Commitments and Contingencies – (continued)

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 11 — Commitments and Contingencies – (continued)

Note 12 — Supplemental Condensed Consolidating Financial Information

EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 12 — Supplemental Condensed Consolidating Financial Information – (continued)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance Sheet As of December 31, 2015(UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance SheetAs of June 30, 2015 (AUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of OperationsThree Months Ended December 31, 2015 (UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of OperationsThree Months Ended December 31, 2014(UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of OperationsSix Months Ended December 31, 2015(UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of OperationsSix Months Ended December 31, 2014(UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash FlowsSix Months Ended December 31, 2015(UNAUDITED)

EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash Flows Six Months Ended December 31, 2014(UNAUDITED)

Overview

Known Trends and Uncertainties

Results of Operations

Three Months Ended December 31, 2015 Compared to Three Months Ended December 31, 2014

Revenues

Price and Volume Variances

Price Variances

Volume Variances

Costs and Expenses and Other (Income) Expense

Income Taxes

Six Months Ended December 31, 2015 Compared to Six Months Ended December 31, 2014

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(In thousands)

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(In thousands)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2015
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Balance Sheet
As of June 30, 2015
(AUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2015
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2014
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2015
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2014
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2015
(UNAUDITED)

EPL OIL & GAS, INC.

Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2014
(UNAUDITED)

EPL OIL & GAS, INC. 10-Q