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 ~~March~~September 3130, 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 ~~Web site~~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.Financial Statements:
Item 1.Unaudited Consolidated Financial Statements		1
Condensed Consolidated Balance Sheets as of March 31, 2015 (Unaudited) and June 30, 2014		1
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Condensed Consolidated Statements of Operations (Unaudited) for the three and nine months ended March 31, 2015 and 2014		2
Item 3.Quantitative and Qualitative Disclosures about Market Risk		36
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) for the three and nine months ended March 31, 2015		3
Item 4.Controls and Procedures		37
Condensed Consolidated Statements of Cash Flows (Unaudited) for the nine months ended March 31, 2015 and 2014		4
Notes to Condensed Consolidated Financial Statements (Unaudited)		5
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3.Quantitative and Qualitative Disclosures about Market Risk		39
Item 4.Controls and Procedures		41
PART II — OTHER INFORMATION
Item 1.Legal Proceedings		4239
Item 1A.Risk Factors		4239
Item 2.Unregistered Sales of Equity Securities and Use of Proceeds		4439
Item 3.Defaults Upon Senior Securities		4439
Item 4.Mine Safety Disclosures		4439
Item 5.Other Information		4439
Item 6.Exhibits		4439
SIGNATURES		40
EXHIBIT INDEX		41

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this quarterly report on Form 10-Q (~~the~~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 ~~our~~certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current ~~expectations~~conditions and ~~beliefs~~ ~~concerning~~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 ~~as and when made~~, ~~there~~such ~~can~~statements beare nonot ~~assurance~~guarantees ~~that~~of future ~~developments~~performance ~~affecting~~and usthe ~~will~~actual beresults ~~those~~or ~~that~~developments weanticipated ~~anticipate.~~may ~~All~~not ~~comments~~be ~~concerning~~realized ~~our~~or, ~~expectations~~even ~~for~~if ~~future~~substantially ~~revenues~~realized, ~~and~~may ~~operating~~not ~~results~~have ~~are~~the ~~based~~expected onconsequences ~~our~~to ~~forecasts~~or ~~for~~effects ~~our~~on ~~existing operations and do not include~~ the ~~potential~~Company’s ~~impact~~business ofor ~~any future acquisitions~~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 future financial condition, results of operations, revenues, cash flows and expenses;

•

our future levels of indebtedness, liquidity, and compliance with debt covenants;

•

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

•

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 ~~risk~~risks;

• uncertainties in estimating our oil and gas reserves;

•

replacing our oil and gas reserves;

• ~~uncertainties~~geographic inconcentration ~~exploring~~of ~~for~~our ~~and producing oil and gas~~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;

• 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

• estimates of proved reserve quantities and net present values of those reserves.

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 Transition Report on Form 10-K for the period ended June 30, 2014 (the “2014 Transition Report”) and Part II, “Item 1A. Risk Factors” in this Quarterly Report.

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~~Readers~~• ~~are~~costs ~~cautioned~~associated ~~not~~with toperfecting ~~place~~title ~~undue~~for ~~reliance~~mineral onrights ~~forward-looking~~in ~~statements,~~some ~~which speak only as~~ of ~~the~~our ~~date~~properties; ~~hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.~~ 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 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. ~~FINANCIAL~~Unaudited ~~STATEMENTS~~Consolidated Financial Statements.

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

	March 31, 2015			June 30, 2014
	September 30, 2015			June 30, 2015
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	95—		$	~~5,601~~217
Trade accounts receivable – net		5355,~~992~~146			7271,~~301~~323
Derivative financial instruments		21,~~906~~970			—888
Deferred tax asset		16,760			24,587
Restricted cash		6,025			6,024
Prepaid expenses		61,~~135~~523			261,~~521~~831
Total current assets		7964,~~888~~664			~~129~~80,~~010~~283
Property and equipment, under the full cost method of accounting, including $679.1 million and $908.5 million of unevaluated properties not being amortized at March 31, 2015 and June 30, 2014, respectively		2,053,534			3,205,187
Property and equipment, net – full cost method of accounting, including $397.7 million and $435.4 million of unevaluated properties not being amortized at September 30, 2015 and June 30, 2015, respectively		1,053,954			1,415,025
Goodwill		—			329,293
Restricted cash		21,008			—
Restricted cash		6,024			6,023
Other assets and debt issuance costs, net of accumulated amortization		947			1,039
Other assets and debt issuance costs, net of accumulated amortization		1,068			317
Total assets	$	1,140,573		$	1,496,347
Total assets	$	2,140,514		$	3,669,830
LIABILITIES AND STOCKHOLDER'S DEFICIT
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	3042,~~398~~797		$	9224,~~981~~548
Due to EGC		~~182~~190,~~792~~401			4170,~~960~~728
Accrued liabilities		7271,~~397~~550			~~161~~95,~~518~~981
Asset retirement obligations		3915,~~831~~839			3938,~~831~~056
Derivative financial instruments		—			261,~~440~~057
Current maturities of long-term debt		31,~~176~~684			—3,364
Total current liabilities		~~328~~322,~~594~~271			~~325~~333,~~730~~734
Long-term debt, less current maturities		~~692~~686,~~855~~018			1689,~~025,566~~459
Intercompany promissory note		325,000			—
Promissory note payable to EGC		325,000			325,000
Asset retirement obligations		~~214~~196,~~355~~004			~~232~~202,~~864~~306
Deferred tax liabilities		49,308			483,798
Total liabilities		1,529,293			1,550,499
Derivative financial instruments		—			2,140
Commitments and contingencies (Note 10)
Other		—			6
Stockholder's deficit:
Total liabilities		1,610,112			2,070,104
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at September 30, 2015 and June 30, 2015		—			—
Commitments and contingencies (Note 12)
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; shares issued and outstanding: 1,000 at September 30, 2015 and June 30, 2015		—			—
Stockholder’s equity:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at March 31, 2015 and June 30, 2014		—			—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; 1,000 shares issued and outstanding at March 31, 2015 and June 30, 2014		—			—
Additional paid-in capital		1,599,341			1,599,341
Accumulated other comprehensive income (loss)		3,790			(6,252	)
Accumulated deficit		(1,988,061	)		(1,653,493	)
Retained earnings (accumulated deficit)		(1,072,729	)		6,637
Total stockholder's deficit		(388,720	)		(54,152	)
Total stockholder’s equity		530,402			1,599,726
Total liabilities and stockholder's deficit	$	1,140,573		$	1,496,347
Total liabilities and stockholder’s equity	$	2,140,514		$	3,669,830

See accompanying ~~notes~~Notes to ~~condensed~~Consolidated ~~consolidated~~Financial ~~financial statements~~Statements.

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EPL OIL & GAS, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (In thousands, except per share data)

	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	Three Months Ended September 30,
	Three Months Ended March 31, 2015			Nine Months Ended March 31, 2015			Three Months Ended March 31, 2014			Nine Months Ended March 31, 2014
	2015			2014
Revenue:
Revenues
Oil and natural gas	$	87,253		$	417,043		$	158,470		$	483,229
Oil sales	$	73,372		$	158,316
Other		—			932			1,021			2,864
Natural gas sales		12,618			13,954
Total revenue		87,253			417,975			159,491			486,093
Gain on derivative financial instruments		2,778			21,857
Costs and expenses:
Total Revenues		88,768			194,127
Lease operating		49,571			161,175			41,734			123,203
Costs and expenses
Transportation		543			2,317			900			3,125
Lease operating		26,153			56,300
Exploration expenditures and dry hole costs		—			—			4,941			23,033
Transportation		723			625
Impairment of oil and natural gas properties		430,859			1,113,727			61			827
Depreciation, depletion and amortization		57,660			73,745
Goodwill impairment		—			329,293			—			—
Accretion of asset retirement obligations		6,741			6,181
Depreciation, depletion and amortization		73,576			235,868			45,645			146,146
Impairment of oil and natural gas properties		308,078			—
Accretion of liability for asset retirement obligations		5,509			17,788			6,997			23,098
Goodwill impairment		—			329,293
General and administrative		11,998			26,850			10,287			23,923
General and administrative expense		7,944			8,042
Taxes, other than on earnings		~~3,057~~(935	)		72,~~529~~528			~~2,472~~			~~8,363~~
Gain on sales of assets		—			—			—			(1,825	)
Other		—			21
Other		(3	)		18			(942	)		27,457
Total costs and expenses		406,364			476,735
Total costs and expenses		575,110			1,894,565			112,095			377,350
Operating Loss		(317,596	)		(282,608	)
Income (loss) from operations		(487,857	)		(1,476,590	)		47,396			108,743
Other income (expense):
Other income (expense):
Interest income		12			—
Interest income		6			10			10			82
Interest expense		(16,984	)		(10,901	)
Interest expense		(12,558	)		(34,406	)		(13,304	)		(39,479	)
Total other expense, net		(16,972	)		(10,901	)
Loss on derivative instruments		(579	)		(635	)		(13,142	)		(68,482	)
Loss before income taxes		(334,568	)		(293,509	)
Total other expense		(13,131	)		(35,031	)		(26,436	)		(107,879	)
Income tax expense		—			12,847
Income (loss) before income taxes		(500,988	)		(1,511,621	)		20,960			864
Net loss	$	(334,568	)	$	(306,356	)
Income tax expense (benefit)		(190,471	)		(432,255	)		7,629			875
Net income (loss)	$	(310,517	)	$	(1,079,366	)	$	13,331		$	(11	)
Basic income (loss) per share							$	0.34		$	—
Diluted income (loss) per share							$	0.34		$	—
Weighted average common shares used in computing income (loss) per share:
Basic								38,714			38,648
Diluted								39,233			38,648

See accompanying ~~notes~~Notes to ~~condensed~~Consolidated ~~consolidated~~Financial ~~financial statements~~Statements.

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

	Three Months Ended March 31, 2015			Nine Months Ended March 31, 2015
	Three Months Ended September 30,
Net loss	$	(310,517	)	$	(1,079,366	)
	2015			2014
Other comprehensive income (loss)
Cash flows from operating activities:
Crude oil and natural gas cash flow hedges
Net loss	$	(334,568	)	$	(306,356	)
Unrealized change in fair value net of ineffective portion		(954	)		43,220
Adjustments to reconcile net loss to net cash provided by operating activities:
Effective portion reclassified to earnings during the period		(2,510	)		(27,586	)
Depreciation, depletion and amortization		57,660			73,745
Total other comprehensive income (loss)		(3,464	)		15,634
Accretion of asset retirement obligations		6,741			6,181
Deferred income tax expense (benefit)		(1,282	)		5,592
Change in fair value of derivative financial instruments		(2,064	)		(20,045	)
Net other comprehensive income (loss)		(2,182	)		10,042
Deferred income taxes		—			12,847
Comprehensive loss	$	(312,699	)	$	(1,069,324	)
Impairment of oil and natural gas properties		308,078			—
Goodwill impairment		—			329,293
Amortization of premium and debt issuance costs		(3,352	)		(2,534	)
Changes in operating assets and liabilities:
Trade accounts receivable		17,176			6,410
Prepaid expenses and other assets		312			(5,699	)
Accounts payable and accrued liabilities		2,818			(23,804	)
Asset retirement obligation settlements		(36,865	)		(7,190	)
Net cash provided by operating activities		15,936			62,848
Cash flows used in investing activities:
Property acquisitions		—			(260	)
Capital expenditures		(13,120	)		(111,136	)
Other property and equipment additions		—			(40	)
Net cash used in investing activities		(13,120	)		(111,436	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt		(1,698	)		—
Cash restricted under revolving credit facility related to property sold		(21,008	)		—
Advances from EGC		19,673			43,010
Net cash provided by (used in) financing activities		(3,033	)		43,010
Net decrease in cash and cash equivalents		(217	)		(5,578	)
Cash and cash equivalents at beginning of period		217			5,601
Cash and cash equivalents at end of period	$	—		$	23
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Non-cash investing information:
Changes in capital expenditures accrued in accounts payable	$	(10,058	)	$	19,285
Changes in asset retirement obligations		1,605			564
Cash paid during the period for:
Interest	$	22,694		$	23,922

See accompanying ~~notes~~Notes to ~~condensed~~Consolidated ~~consolidated~~Financial ~~financial statements~~Statements.

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

	SUCCESSOR COMPANY			PREDECESSOR COMPANY
	Nine Months Ended March 31, 2015			Nine Months Ended March 31, 2014
Cash flows from operating activities:
Net loss	$	(1,079,366	)	$	(11	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		235,868			146,146
Accretion of liability for asset retirement obligations		17,788			23,098
Change in derivative financial instruments
Proceeds from sale of derivative financial instruments		4,559			—
Unrealized (gain) loss on derivative financial instruments		(1,256	)		44,438
Non-cash compensation		—			6,321
Deferred income taxes		(432,255	)		1,025
Exploration expenditures		—			1,876
Impairment of oil and natural gas properties		1,113,727			827
Goodwill impairment		329,293			—
Amortization of premium, discount and deferred financing costs on debt		(7,688	)		4,149
Gain on sales of assets		—			(1,825	)
Other		—			20,905
Changes in operating assets and liabilities:
Trade accounts receivable		19,267			(8,433	)
Prepaid expenses and other assets		20,702			11,057
Accounts payable and accrued liabilities		(91,270	)		50,034
Asset retirement obligation settlements		(39,025	)		(41,584	)
Net cash provided by operating activities		90,344			258,023
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		—			51,757
Property acquisitions		(350	)		(83,412	)
Deposit for Nexen Acquisition		—			(7,040	)
Capital expenditures		(271,496	)		(268,905	)
Other property and equipment additions		(58	)		(984	)
Proceeds from sale of assets		—			80
Net cash used in investing activities		(271,904	)		(308,504	)
Cash flows provided by (used in) financing activities:
Proceeds from (repayments of) indebtedness		(325,000	)		55,000
Proceeds from intercompany promissory note		325,000			—
Advances from EGC		177,832			—
Deferred financing costs		(1,089	)		(206	)
Purchase of shares into treasury		—			(4,544	)
Exercise of stock options		—			794
Other		(689	)		—
Net cash provided by financing activities		176,054			51,044
Net increase (decrease) in cash and cash equivalents		(5,506	)		563
Cash and cash equivalents at beginning of period		5,601			3,885
Cash and cash equivalents at end of period	$	95		$	4,448

(1) Organization and Summary of Significant Accounting Policies

Nature of Operations. ~~See~~EPL ~~accompanying~~Oil ~~notes~~& Gas, Inc. (referred to ~~condensed~~herein ~~consolidated~~as ~~financial~~“we,” ~~statements~~“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.

4Principles 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 interest in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

~~TABLE~~Interim OFFinancial ~~CONTENTS~~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 our 2015 Annual Report.

~~EPL~~Use ~~OIL~~of &Estimates. The ~~GAS~~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, ~~INC~~plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. ~~AND~~Accordingly, ~~SUBSIDIARIES~~our ~~NOTES~~accounting TOestimates ~~CONDENSED~~require ~~CONSOLIDATED~~exercise ~~FINANCIAL~~of ~~STATEMENTS~~judgment ~~(UNAUDITED)~~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 (1“FASB”) ~~Organization~~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 ~~Basis~~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 ~~Presentation~~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.

~~Nature~~In ofAugust ~~Operations. EPL Oil & Gas~~2014, ~~Inc.~~the ~~was~~FASB ~~incorporated~~issued asASU aNo. ~~Delaware corporation on January 29, 1998 and is a wholly~~2014-~~owned subsidiary of Energy XXI Gulf Coast~~15, ~~Inc.~~Disclosure ~~(“EGC”), a Delaware corporation, which is an indirect wholly-owned subsidiary~~ of ~~Energy~~Uncertainties ~~XXI~~about ~~Ltd,~~ an ~~exempted~~Entity’s ~~company~~Ability ~~under~~to ~~the~~Continue ~~laws~~as ofa ~~Bermuda~~Going Concern (“~~Energy~~ASU ~~XXI~~2014-15”). ~~References~~ASU in2014-15 ~~this~~requires ~~Quarterly~~management ~~Report~~ to ~~“we,”~~assess ~~“our,” “us,” “the Company” or “EPL”) are to EPL Oil & Gas, Inc. and its wholly-owned subsidiaries. We operate as~~ an ~~independent~~entity’s oil and natural gas exploration and production company with 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. 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, par value $0.001 per share, were converted, in the aggregate, into the right to receive merger consideration consisting of approximately 65% in cash and 35% in shares of common stock of Energy XXI, par value $0.005 per share. 4

~~The~~TABLE ~~Merger~~OF 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. As a result, our separate financial statements reflect the new basis of accounting recorded by Energy XXI upon the acquisition. As such, in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”), due to our new basis of accounting, our financial statements include a black line denoting that our financial statements covering periods prior to the date of the Merger are not comparable to our financial statements as of and subsequent to the date of the Merger. References to the “Predecessor Company” refer to reporting dates of the Company through June 3, 2014, reflecting results of operations and cash flows of the Company prior to the Merger on our historical accounting basis; subsequent thereto, the Company is referred to as the “Successor Company,” reflecting the impact of pushdown accounting and the results of operations and cash flows of the Company subsequent to the Merger. CONTENTS

EnergyEPL XXIOIL follows& the “full cost” method of accounting for its oil and gas producing activitiesGAS, while we had historically followed the “successful efforts” method of accountingINC. SubsequentAND toSUBSIDIARIES theNOTES Merger,TO weCONSOLIDATED convertedFINANCIAL ourSTATEMENTS accounting method from successful efforts to the full cost method of accounting to be consistent with Energy XXI’s method of accounting pursuant to SEC guidance, which requires a reporting entity that follows the full cost method to apply that method to all of its operations and to the operations of its subsidiaries. Under U.S. GAAP, a change in accounting method is required to be applied retroactively in order to provide comparable historical period information to users of financial statements. However, due to the new basis of accounting established as a result of the Merger transaction and pushdown accounting, our financial statements are no longer comparable to those of periods prior to the Merger and we have applied the full cost method of accounting on a prospective basis from the date of the Merger. (UNAUDITED)

The(1) accompanyingOrganization consolidatedand financialSummary statements include the accounts of EPLSignificant andAccounting itsPolicies wholly-owned– subsidiaries and have been prepared in accordance with U.S. GAAP. All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. (continued)

~~Interim~~ability ~~Financial~~to ~~Statements. The~~continue ~~accompanying~~as ~~consolidated~~a ~~financial~~going ~~statements~~concern ~~have~~and ~~been~~to ~~prepared~~provide inrelated ~~accordance~~footnote ~~with~~disclosures Uin certain circumstances.S. ~~GAAP~~The standard is effective for ~~interim~~annual ~~financial~~periods ~~information~~ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the ~~instructions~~provisions toof ~~Form~~ASU 102014-Q15 and assessing the impact, if any, it may have on our consolidated financial statements.

5In 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.

~~TABLE~~The OFASU ~~CONTENTS~~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.

~~EPL~~In ~~OIL~~September ~~& GAS~~2015, ~~INC~~the FASB issued ASU No. ~~AND~~2015-16, ~~SUBSIDIARIES~~Business ~~NOTES~~Combinations TO(Topic ~~CONDENSED~~805) — Simplifying ~~CONSOLIDATED~~the ~~FINANCIAL~~Accounting ~~STATEMENTS~~for Measurement-Period Adjustments (~~UNAUDITED~~“ASU 2015-16”). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. It also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. 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 prospectively. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our consolidated financial statements.

(12) OrganizationPushdown Accounting and Basis of Presentation – (continued)Goodwill

~~Article~~On 10June of3, ~~Regulation~~2014, ~~S-X.~~Energy ~~Accordingly~~XXI, ~~they~~EGC, doClyde ~~not~~Merger ~~include~~Sub, ~~all~~Inc., ofa ~~the~~wholly ~~information~~owned ~~and~~subsidiary ~~footnotes~~of ~~required~~EGC by(“Merger ~~U.S.~~Sub”), ~~GAAP~~and ~~for~~EPL, ~~complete~~completed ~~financial~~the ~~statements.~~transactions Incontemplated by the ~~opinion~~Agreement and Plan of ~~management~~Merger, ~~all~~dated ~~adjustments~~as of aMarch ~~normal~~12, 2014 (as amended, the “Merger Agreement”), by and ~~recurring~~among ~~nature~~Energy ~~considered~~XXI, ~~necessary~~EGC, ~~for~~Merger aSub, ~~fair~~and ~~presentation~~EPL, ~~have~~pursuant ~~been~~to ~~included~~which inMerger Sub was merged with and into EPL with EPL continuing as the ~~accompanying~~surviving ~~consolidated~~corporation ~~financial~~(the ~~statements~~“Merger”). ~~The~~Pursuant ~~results~~to the Merger Agreement, at the effective time of ~~operations~~the ~~for~~Merger (the ~~interim~~“Effective ~~period~~Time”), ~~are~~the ~~not~~issued ~~necessarily~~and ~~indicative~~outstanding shares of EPL common stock, par value $0.001 per share (“EPL Common Stock”), were converted, in the ~~results~~aggregate, ~~that~~into ~~will~~the beright ~~realized~~to ~~for~~receive merger consideration (the ~~entire~~“Merger ~~fiscal~~Consideration”) ~~year~~consisting of approximately 65% in cash and 35% in shares of common stock of Energy XXI, par value $0.005 ~~These~~per ~~consolidated~~share ~~financial~~(“Energy ~~statements~~XXI ~~should~~Common beStock”). ~~read~~The Merger resulted in ~~conjunction~~EPL ~~with~~becoming an indirect, wholly owned subsidiary of Energy XXI. Therefore, in the ~~consolidated~~preparation of our financial statements, we have applied “pushdown” accounting, based on guidance from the Securities and ~~notes~~Exchange ~~thereto included~~Commission (“SEC”). Pushdown accounting refers to the use of the acquiring entity’s basis of accounting in ~~our~~the ~~2014~~preparation ~~Transition~~of ~~Report~~the acquired entity’s financial statements.

~~Use~~In ofaccordance ~~Estimates. The preparation of consolidated financial statements in conformity~~ with ~~U.S. GAAP requires management to make estimates and assumptions that affect~~ the ~~reported~~acquisition ~~amounts~~method of ~~assets~~accounting, ~~and liabilities and disclosure of contingent assets and liabilities at~~ the ~~dates~~purchase ofprice ~~the~~established ~~consolidated~~in ~~financial statements and~~ the ~~reported~~Merger ~~amounts~~was ofallocated ~~revenues~~to ~~and expenses during~~ the ~~reporting~~assets ~~period.~~acquired ~~Estimates of proved reserves are key components of our depletion rate for our proved oil~~ and ~~natural~~liabilities ~~gas~~assumed ~~properties~~based ~~and~~on ~~the~~their ~~full~~estimated ~~cost ceiling test limitation. Other items subject to estimates and assumptions include~~ fair ~~value~~values ~~estimates~~on used in pushdown accounting and accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the ~~estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.~~

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted. 5

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

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

6(2) Pushdown Accounting and Goodwill – (continued)

~~TABLE~~acquisition OFdate. ~~CONTENTS~~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.

~~EPL~~ASC ~~OIL~~350, &Intangibles — Goodwill ~~GAS~~and Other (ASC 350), ~~INC~~requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. ~~AND~~Our ~~SUBSIDIARIES~~annual ~~NOTES~~goodwill TOimpairment ~~CONDENSED~~test ~~CONSOLIDATED~~is ~~FINANCIAL~~performed ~~STATEMENTS~~during ~~(UNAUDITED)~~the third quarter each fiscal year.

~~(2)~~Impairment ~~Acquisitions~~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.

~~The~~At ~~South~~September ~~Pass~~30, 492014, ~~Transfer~~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.

OnIn ~~June~~estimating 3,the ~~2014,~~fair ~~Energy~~value ~~XXI~~of ~~GOM,~~our ~~LLC~~reporting unit and our estimated reserves, ~~transferred~~we used an ~~asset~~income ~~package~~approach towhich usestimated ~~consisting~~fair ofvalue ~~certain~~primarily ~~shallow-water~~based ~~GoM~~on ~~shelf~~the ~~oil~~anticipated ~~and~~cash ~~natural~~flows ~~gas~~associated ~~interests~~with in our ~~South~~estimated ~~Pass~~reserves, 49discounted ~~field~~using ~~(the~~a ~~“SP49~~weighted ~~Interests”)~~average ~~for~~cost ~~$230.0~~of ~~million~~capital torate ~~reflect~~based anon ~~economic~~market ~~effective~~participant ~~date~~data. The estimation of ~~June~~the 1,fair ~~2014~~value ~~(the~~of ~~“SP49~~our ~~Transfer”).~~reporting ~~Prior~~unit toincludes the ~~SP49~~use ~~Transfer,~~of wesignificant ~~owned~~inputs anot ~~43.5%~~observable ~~working~~in ~~interest~~the inmarket, ~~certain~~such as estimates of ~~these~~reserves ~~assets~~quantities, ~~and~~the ~~Energy~~weighted ~~XXI~~average ~~owned~~cost aof ~~56.5%~~capital ~~working~~(discount ~~interest~~rate), infuture ~~certain~~pricing ofbeyond ~~these~~a ~~assets~~certain asperiod ~~well~~and asestimated ~~100%~~future ~~interest~~capital inand ~~additional~~operating ~~assets~~costs. inThe ~~the~~use ~~field.~~of these Asunobservable ainputs ~~result~~results ofin the ~~SP49~~fair ~~Transfer,~~value weestimate ~~have~~being ~~become~~classified ~~the~~as ~~sole~~a ~~working~~Level ~~interest~~3 ~~owner~~measurement. ofAlthough we believe the ~~South Pass~~assumptions 49and ~~field.~~estimates Weused ~~financed~~in the ~~SP49~~fair ~~Transfer~~value ~~with~~calculation ~~borrowings~~ of ~~approximately~~our ~~$135~~reporting ~~million~~unit ~~under~~are ~~our~~reasonable ~~prior~~and ~~credit~~appropriate, ~~facility~~different assumptions and aestimates ~~$95~~could ~~million~~materially ~~capital~~impact ~~contribution~~the ~~from~~analysis ~~EGC~~and resulting conclusions.

The(3) followingProperty table summarizes the assets acquired and liabilities assumed in the transfer. Equipment

(In thousands)
Oil and natural gas properties	$	231,271
Asset retirement obligations		(1,086	)
Net assets acquired	$	230,185

The following table summarizes our property and equipment.

The Nexen Acquisition


	September 30, 2015			June 30, 2015
	(In thousands)
Proved oil and natural gas properties	$	3,035,428		$	2,993,012
Unevaluated oil and natural gas properties		397,680			435,429
Other		3,116			3,116
Less: accumulated depreciation, depletion, amortization and impairment		(2,382,270	)		(2,016,532	)
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment	$	1,053,954		$	1,415,025

On January 15, 2014, we acquired from Nexen Petroleum Offshore U.S.A., Inc. (“Nexen”) a 100% working interest in certain shallow-water central GoM shelf oil and natural gas assets for $70.4 million, subject to customary adjustments to reflect the September 1, 2013, economic effective date (the “Nexen Acquisition”). The assets we acquired comprise five leases in the Eugene Island 258/259 field (the “EI Interests”). The Nexen Acquisition was financed with borrowings under our senior secured credit facility with BMO Capital Markets, as lead arranger, and Bank of Montreal, as administrative agent and a lender, and the other lender parties thereto (as amended and restated, the “Prior Senior Credit Facility”). 6

~~The~~TABLE ~~following~~OF table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $5.7 million to reflect an economic effective date of September 1, 2013. CONTENTS

(In thousands)
Oil and natural gas properties	$	82,897
Asset retirement obligations		(18,165	)
Net assets acquired	$	64,732

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The(3) WestProperty Deltaand 29Equipment Acquisition– (continued)

OnAt September 2630, ~~2013,~~2015 weand ~~acquired~~June ~~from~~30, ~~W&T Offshore~~2015, ~~Inc.~~our ~~(“W&T”)~~investment anin ~~asset~~unevaluated ~~package~~properties ~~consisting~~primarily ofrelates ~~certain~~to ~~GoM~~the ~~shelf~~fair value of unproved oil and natural gas ~~interests~~properties indetermined ~~the~~during ~~West Delta 29 field (~~the ~~“WD29 Interests”) for $21~~Merger.8 ~~million~~Costs inassociated ~~cash,~~with ~~subject~~unevaluated toproperties ~~customary~~are ~~adjustments~~transferred to ~~reflect~~evaluated anproperties ~~economic~~upon ~~effective~~the ~~date~~earlier of ~~January~~ 1~~, 2013 (the “WD29 Acquisition”~~). ~~The~~a ~~WD29~~determination ~~Acquisition~~as ~~was~~to ~~funded~~whether ~~with~~there aare ~~portion~~any ofproved ~~the~~reserves ~~proceeds~~related ~~from~~to the ~~sale~~properties, ofor ~~certain~~2) ~~shallow~~ratably ~~water~~over ~~GoM~~a ~~shelf~~period ~~oil~~of ~~and~~time ~~natural~~of ~~gas~~not ~~interests~~more ~~located~~than ~~within~~four ~~the non-operated Bay Marchand field in a tax-deferred exchange of properties~~years.

7Under 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. At September 30, 2015, our ceiling test computations resulted in impairment of our oil and natural gas properties of $308.1 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 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.

TABLE(4) OFAsset CONTENTSRetirement Obligations

~~EPL~~The ~~OIL~~following &table ~~GAS,~~reconciles ~~INC.~~the ~~AND~~changes ~~SUBSIDIARIES~~to ~~NOTES~~our TOasset ~~CONDENSED~~retirement ~~CONSOLIDATED~~obligations. ~~FINANCIAL STATEMENTS (UNAUDITED)~~

(2) Acquisitions – (continued)


	Three Months Ended September 30, 2015
	(in thousands)
Beginning of period total	$	240,362
Accretion expense		6,741
Liabilities incurred		1,605
Liabilities settled		(36,865	)
End of period total		211,843
Less: End of period, current portion		(15,839	)
End of period, noncurrent portion	$	196,004

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $7~~.1 million to reflect an economic effective date of January 1, 2013.~~

(In thousands)
Oil and natural gas properties	$	16,544
Asset retirement obligations		(1,398	)
Net assets acquired	$	15,146

TABLE OF CONTENTS

WeEPL haveOIL accounted& for the Nexen Acquisition and WD29 Acquisition using the acquisition method of accounting for business combinationsGAS, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of their respective acquisition datesINC. InAND theSUBSIDIARIES estimationNOTES ofTO fairCONSOLIDATED value,FINANCIAL managementSTATEMENTS uses various valuation methods including (iUNAUDITED) comparable company analysis, which estimates the value of the acquired properties based on the implied valuations of other similar operations; (ii) comparable asset transaction analysis, which estimates the value of the acquired operations based upon publicly announced transactions of assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of operations based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis. The fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 9, “Fair Value Measurements.”

Results(5) of Operations and Pro Forma InformationIndebtedness

~~Revenues~~The ~~and~~following ~~lease~~table ~~operating~~sets ~~expenses~~forth ~~attributable~~our toindebtedness. ~~acquired interests and properties were as follows:~~

	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	September 30, 2015			June 30, 2015
~~(In thousands)~~	~~Three~~(In ~~Months Ended March 31, 2015~~thousands)			~~Nine Months Ended March 31, 2015~~			~~Three Months Ended March 31, 2014~~		~~Nine Months Ended March 31, 2014~~
SP49 Interests:
8.25% senior notes due 2018	$	536,018		$	539,459
Revenues	$	8,311		$	35,342		$	—	$	—
Revolving credit sub-facility		150,000			150,000
Lease operating expenses	$	837		$	5,200		$	—	$	—
Derivative instruments premium financing		1,684			3,364
EI Interests:
Total debt		687,702			692,823
Revenues	$	4,711		$	24,703		$	8,380	$	8,380
Less current maturities		(1,684	)		(3,364	)
Lease operating expenses	$	6,030		$	16,026		$	3,656	$	3,656
Long term debt		686,018			689,459
WD29 Interests:
Promissory note payable to EGC		325,000			325,000
Revenues	$	1,683		$	8,428		$	3,232	$	6,243
Noncurrent portion of indebtedness	$	1,011,018		$	1,014,459
Lease operating expenses	$	238		$	609		$	59	$	103

WeRevolving haveCredit determined that the presentation of net income attributable to the acquired interests and properties is impracticable due to the integration of the related operations upon acquisition. Sub-Facility

On July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver (the “Eleventh Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”). This facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement (“Revolving Credit Sub-Facility”). 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% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of our outstanding 8.25% senior notes due February 2018 (the “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.

~~TABLE~~This OFfacility, ~~CONTENTS~~as amended, 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.

~~EPL~~Borrowings ~~OIL~~are &limited ~~GAS~~to a borrowing base based on oil and natural gas reserve values which are re-determined on a periodic basis. We and our lenders are currently in the process of our fall borrowing base redetermination, ~~INC~~which we expect to conclude during December 2015. ~~AND~~The ~~SUBSIDIARIES~~Revolving ~~NOTES~~Credit TOFacility ~~CONDENSED~~is ~~CONSOLIDATED~~secured ~~FINANCIAL~~by ~~STATEMENTS~~mortgages on at least 90% of the value of EGC and its subsidiaries’ (~~UNAUDITED~~other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but with the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%.

~~(2)~~Currently, ~~Acquisitions~~the –facility bears interest based on the borrowing base usage, at either the applicable London Interbank Offered Rate (~~continued~~“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 following supplemental pro forma information presents consolidated results of operations as if the WD 29 Acquisition, the Nexen Acquisition and the SP49 Transfer had occurred on July 1, 2012. In addition, this information has been prepared to reflect the Merger and pushdown accounting as if it occurred on July 1, 2012. The supplemental unaudited pro forma information was derived from a) our historical condensed consolidated statements of operations and b) unaudited revenues and direct operating expenses of the SP49 Interests, WD29 Interests and the EI Interests as derived from the records of the applicable seller provided to us in connection with the acquisitions. This information does not purport to be indicative of results of operations that would have occurred had the transactions occurred on July 1, 2012, nor is such information indicative of any expected future results of operations. The most significant pro forma adjustments for the three and nine months ended March 31, 2014, were the following: 8

a.TABLE ~~Exclude~~OF $5.0 million and $22.0 million, respectively, of exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with the full cost method of accounting.CONTENTS

b.EPL IncreaseOIL DD&A expenseGAS, by $25INC.0 millionAND andSUBSIDIARIES $82.6NOTES million,TO respectively,CONSOLIDATED toFINANCIAL correspondSTATEMENTS with the full cost method of accounting.(UNAUDITED)

c. Decrease interest expense $3.4 million and $10.0 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of our 8.25% senior notes due February 2018 (the5) “8.25%Indebtedness Senior– Notes”(continued).

	PRO FORMA
(in thousands, except per share data)	Three Months Ended March 31, 2014		Nine Months Ended March 31, 2014
Revenue	$	176,833	$	563,103
Net income		11,434		2,289
Basic income per share		0.29		0.06
Diluted income per share		0.29		0.06

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.

~~(3)~~Lender ~~Pushdown~~consent ~~Accounting~~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 ~~Goodwill~~disposition.

AsThe ~~described~~First inLien ~~Note~~Credit 1Agreement, ~~the~~as ~~Merger~~amended, ~~resulted~~requires inthat EPL ~~becoming~~and anEGC ~~indirect,~~maintain ~~wholly-owned~~certain ~~subsidiary~~financial ofcovenants ~~Energy~~separately ~~XXI.~~for ~~Therefore,~~so welong ~~applied~~as ~~“pushdown”~~the ~~accounting,~~8.25% ~~based~~Senior onNotes ~~guidance~~remain ~~from~~outstanding. ~~the~~We ~~SEC.~~are Incurrently ~~accordance~~subject ~~with~~to the ~~acquisition~~following ~~method~~financial ofcovenants: ~~accounting,~~(a) ~~the~~a ~~purchase~~consolidated ~~price~~maximum ~~established~~first inlien ~~the~~leverage ~~Merger~~ratio ~~was~~of ~~allocated~~1.25 to ~~the~~1.0 ~~assets acquired~~ and ~~liabilities~~(b) ~~assumed~~a ~~based~~consolidated onmaximum ~~their~~secured ~~estimated~~leverage ~~fair~~ratio ~~values~~of onno ~~the~~more ~~acquisition~~than ~~date~~3.75 ~~The~~to ~~fair~~1.0. ~~value~~If ~~estimates~~the ~~were~~8.25% ~~based~~Senior ~~on,~~Note ~~but~~are ~~not~~no ~~limited~~longer ~~to,~~outstanding ~~quoted~~and ~~market~~certain ~~prices,~~other ~~where~~conditions ~~available;~~are ~~expected~~met, ~~future~~EGC ~~cash~~will ~~flows~~be ~~based~~subject onto ~~estimated~~the ~~reserve~~following ~~quantities;~~financial ~~estimated~~covenants ~~costs~~on toa ~~produce~~consolidated ~~and~~basis: ~~develop reserves;~~(a) ~~current~~a ~~replacement~~consolidated ~~cost~~maximum ~~for~~net ~~similar~~first ~~capacity~~lien ~~for~~leverage ~~certain~~ratio ~~fixed~~of ~~assets;~~1.25 ~~market~~to ~~rate~~1.0, (b) ~~assumptions~~a ~~for~~consolidated ~~contractual~~maximum ~~obligations;~~net ~~appropriate~~secured ~~discount~~leverage ~~rates~~ratio ~~and~~of ~~growth~~no ~~rates;~~more ~~and~~than ~~crude~~3.75 ~~oil~~to ~~and~~1.0, ~~natural~~provided ~~gas~~that ~~forward~~if ~~prices~~the 8.25% ~~The~~Senior ~~excess~~Notes ofare ~~the~~refinanced ~~total~~with ~~consideration~~new ~~over~~secured debt, the ~~estimated~~liens ~~fair value~~ of ~~the~~which ~~amounts~~are ~~initially~~junior ~~assigned~~in priority to the ~~identifiable~~Revolving ~~assets~~Credit ~~acquired~~Facility ~~and~~indebtedness, ~~liabilities~~then ~~assumed~~the ~~was~~maximum ~~recorded~~ratio aspermitted ~~goodwill~~would be 4.25 ~~Goodwill~~to ~~recorded~~1.0, inand ~~connection~~(c) ~~with~~a ~~the~~minimum ~~Merger~~current isratio ~~not~~of ~~deductible~~no ~~for~~less ~~income~~than ~~tax~~1.0 ~~purposes~~to 1.0.

OnSince ~~April~~required 2,lender ~~2013,~~consent weto ~~sold~~the ~~certain~~specific ~~shallow~~terms ~~water~~of ~~GoM~~the ~~shelf~~transaction ~~oil~~with ~~and~~respect ~~natural~~to ~~gas~~the ~~interests~~sale ~~located~~of ~~within~~ the ~~non-operated~~East Bay ~~Marchand~~ field tohad ~~Chevron~~not ~~U.S.A.~~been ~~Inc.~~obtained, ~~(“Chevron”)~~EGC ~~with~~and anEPL ~~effective~~were ~~date~~in oftechnical ~~January~~default 1under the First Lien Credit Agreement at June 30, ~~2013~~2015. InOn ~~September~~July ~~2014~~14, 2015, we ~~were~~obtained ~~informed~~a bywaiver ~~Chevron~~to ~~that~~this ~~the~~event ~~final~~of ~~settlement~~default, ~~statement~~which ~~did~~waiver ~~not~~required ~~reflect~~us to deposit $21 million into an account subject to a ~~portion~~control agreement in favor of ~~production~~the inadministrative agent under the ~~months~~First ofLien ~~January~~Credit ~~2013~~Agreement. ~~and~~Such ~~February~~amount ~~2013~~will ~~totaling~~remain toon ~~approximately~~deposit ~~$2.1~~until ~~million.~~the ~~After~~next ~~review~~redetermination of ~~relevant~~the ~~supporting~~borrowing ~~documents~~base, weunless ~~agreed~~used to ~~reimburse~~repay ~~Chevron~~a ~~approximately~~borrowing ~~$2.1~~base ~~million~~deficiency. ~~This~~Upon ~~resulted~~the next redetermination, any amounts remaining in the account will be used to make an ~~increase~~immediate inpayment ~~liabilities~~toward ~~assumed~~any byborrowing ~~Energy~~base ~~XXI~~deficiency inat the ~~Merger~~time of such redetermination, and aso long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC.

9As of September 30, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are party with EGC, and we were in compliance with all covenants thereunder. As part of our quarterly compliance certificates required under our revolving credit agreement and also as a condition to borrow funds or issue letters of credit under our revolving credit agreement, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our revolving credit facility, as amended to date. 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. In addition, based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods, including periods prior to June 30, 2016. We continue to focus on reducing our leverage and are working with our bank group on certain amendments to the First Lien Credit Agreement to address these concerns. There can be no assurance any of these discussions or transactions will prove successful. 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

~~TABLE OF CONTENTS~~9

~~EPL~~TABLE ~~OIL~~OF ~~& GAS, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)~~CONTENTS

(3)EPL PushdownOIL Accounting& andGAS, GoodwillINC. –AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continuedUNAUDITED)

corresponding(5) increaseIndebtedness in– goodwill of approximately $2.1 million; accordingly the June 30, 2014 condensed consolidated balance sheet has been retrospectively adjusted to increase the value of goodwill. (continued)

~~ASC~~Revolving ~~350,~~Credit ~~Intangibles — Goodwill~~Facility. ~~and~~If ~~Other~~the ~~(ASC~~lenders ~~350),~~under ~~requires~~the ~~that~~Revolving ~~intangible~~Credit ~~assets~~Facility ~~with~~were ~~indefinite~~to ~~lives,~~accelerate ~~including~~the ~~goodwill,~~indebtedness beunder ~~evaluated~~the ~~for~~Revolving ~~impairment~~Credit onFacility anas ~~annual~~a ~~basis~~result orof ~~more~~such ~~frequently~~defaults, ifsuch ~~events~~acceleration ~~occur~~could cause a cross-default or ~~circumstances~~cross-acceleration ~~change~~of ~~that~~all ~~could~~of ~~potentially~~our ~~result~~other inoutstanding ~~impairment~~indebtedness. ~~Our~~Such ~~annual~~a ~~goodwill~~cross-default ~~impairment~~or ~~test~~cross-acceleration iscould ~~performed~~have asa wider impact on our liquidity than might otherwise arise from a default or acceleration of ~~the~~a ~~last~~single ~~day~~debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the ~~fourth~~lenders ~~quarter~~under ~~each~~the ~~fiscal~~affected ~~year~~debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

ImpairmentPromissory 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. Note

AtOn ~~September~~March 3012, ~~2014~~2015, wein ~~conducted~~connection awith ~~qualitative~~EGC’s ~~goodwill~~issuance ~~impairment~~of ~~assessment~~its by11.0% ~~examining~~senior ~~relevant~~secured ~~events~~second ~~and~~lien ~~circumstances~~notes ~~that~~due ~~could~~2020 ~~have~~(the a“11.0% ~~negative impact on our goodwill~~Notes”), ~~such~~we asentered ~~macroeconomic~~into ~~conditions,~~a ~~industry~~$325.0 ~~and~~million ~~market~~secured ~~conditions,~~second ~~cost~~lien ~~factors~~promissory ~~that~~note ~~have~~between aus, ~~negative~~as ~~effect~~the onmaker, ~~earnings~~ and ~~cash flows~~EGC, ~~overall~~as ~~financial~~the ~~performance,~~payee ~~dispositions~~(the ~~and~~“Promissory ~~acquisitions,~~Note”). ~~and~~Proceeds ~~any~~from ~~other~~the ~~relevant~~Promissory ~~events~~Note orwere ~~circumstances.~~used ~~After~~to ~~assessing~~repay ~~the~~a ~~relevant~~like ~~events~~amount ~~and~~of ~~circumstances~~the ~~for~~outstanding borrowings under the ~~qualitative~~Revolving ~~impairment~~Credit ~~assessment,~~Sub-Facility. weThe ~~determined~~Promissory ~~that~~Note ~~performing~~bears ainterest ~~quantitative~~at ~~goodwill~~an ~~impairment~~annual ~~test~~rate ~~was~~of ~~necessary.~~10%, Inhas ~~the~~a ~~first~~maturity ~~step~~date of ~~the goodwill~~October ~~impairment~~9, ~~test~~2018, weand ~~determined~~is ~~that~~secured ~~the~~by ~~fair~~a ~~value~~second priority lien on certain of our ~~reporting~~assets ~~unit~~that ~~was~~secure ~~less~~the ~~than~~obligations under the ~~carrying~~First ~~amount,~~Lien ~~including~~Credit ~~goodwill,~~Agreement. ~~primarily~~EGC ~~due~~may torelease ~~price~~the ~~deterioration~~collateral insecuring ~~forward~~the ~~pricing~~Promissory ~~curves~~Note ~~for~~at ~~oil~~any ~~and~~time. ~~natural~~The ~~gas~~note ~~and~~has annot ~~increase~~been, inand ~~our~~will ~~weighted~~not ~~average~~be, ~~cost~~registered ofunder ~~capital~~the ~~used~~Securities toAct ~~estimate~~of ~~fair value~~1933, ~~both~~as ~~factors~~amended ~~which~~or ~~adversely impacted~~ the ~~fair~~securities ~~value~~laws of ~~our~~any ~~estimated~~other ~~reserves~~jurisdiction. ~~Therefore,~~We wehave ~~performed~~an ~~the~~option ~~second~~to ~~step~~prepay ofthis ~~the~~note ~~goodwill~~in ~~impairment~~whole ~~test,~~or ~~which~~in ~~led~~part usat toany ~~conclude~~time, ~~that~~without ~~there~~penalty ~~was~~or nopremium. ~~remaining~~The ~~implied~~note ~~fair~~bears ~~value~~interest ~~attributable~~from tothe ~~goodwill.~~date Asof aissuance ~~result,~~with weinterest ~~recorded~~due aquarterly, ~~goodwill~~in ~~impairment~~arrears, ~~charge~~on ofJanuary ~~$329.3~~5th, ~~million~~April to5th, ~~reduce~~July ~~the~~5th, ~~carrying~~and ~~value~~October of5th, ~~goodwill~~beginning ~~to zero at~~ September 305, ~~2014~~2015.

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 rate8.25% TheSenior 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. Notes

The ~~final~~8.25% ~~valuation~~senior notes consist of ~~assets~~$510.0 ~~acquired~~million ~~and~~in ~~liabilities~~aggregate ~~assumed~~principal isamount ~~not~~($536.0 ~~complete~~million ~~and~~carrying ~~the~~value ~~net~~at ~~adjustments~~September to30, ~~those~~2015) ~~values~~of ~~may~~our ~~result~~8.25% insenior ~~changes~~notes todue ~~carrying~~2018 ~~amounts~~(the ~~initially~~“8.25% ~~assigned~~Senior toNotes”) issued under an Indenture dated February 14, 2011 (the ~~assets~~“2011 ~~and~~Indenture”). ~~liabilities~~The ~~based~~8.25% onSenior Notes bear interest from the ~~initial~~date ~~fair~~of ~~value~~their ~~analysis~~issuance at ~~the~~an ~~time~~annual rate of ~~the~~8.25% ~~Merger~~with interest due semi-annually, in arrears, on February 15th and August 15th of each year. The ~~principal~~8.25% ~~remaining~~Senior ~~items~~Notes toare befully ~~valued~~and ~~are~~unconditionally ~~tax~~guaranteed, ~~assets~~jointly and ~~liabilities~~severally, on an unsecured senior basis initially by each of our existing direct and ~~any~~indirect ~~related~~domestic ~~valuation~~subsidiaries ~~allowances,~~(other ~~which~~than immaterial subsidiaries). The 8.25% Senior Notes will bemature ~~finalized~~on inFebruary ~~connection~~15, ~~with~~2018. ~~the~~As ~~filing~~a result of ~~related~~pushdown ~~tax~~accounting, ~~returns~~the effective interest rate on the 8.25% Senior Notes is approximately 5.8%.

During October 2015, we repurchased $29.8 million in aggregate principal amount of the 8.25% Notes due 2018 in open market transactions at a total price of approximately $10.0 million, and we will record a gain on this repurchase of approximately $19.8 million, plus the amount of associated unamortized premium, during the three months ended December 31, 2015.

TABLEDerivative OFInstruments CONTENTSPremium Financing

~~EPL~~We ~~OIL~~finance &premiums ~~GAS~~on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Sub-Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Sub-Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, ~~INC~~net of derivative instrument premium financing. ~~AND~~As ~~SUBSIDIARIES~~of ~~NOTES~~September TO30, ~~CONDENSED~~2015, ~~CONSOLIDATED~~our ~~FINANCIAL~~outstanding ~~STATEMENTS~~derivative ~~(UNAUDITED)~~instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $1.7 million.

~~(4) Earnings Per Share~~10

~~The~~TABLE ~~following~~OF ~~table sets forth the calculation of basic and diluted weighted average shares outstanding and earnings per share for the indicated periods for the Predecessor Company.~~ CONTENTS

	Three Months Ended March 31, 2014			Nine Months Ended March 31, 2014
	(in thousands, except per share data)
Income (numerator):
Net income (loss)	$	13,331		$	(11	)
Net income attributable to participating securities		(166	)		—
Net income (loss) attributable to common shares	$	13,165		$	(11	)
Weighted average shares (denominator):
Weighted average shares – basic		38,714			38,648
Dilutive effect of stock options		519			—
Weighted average shares – diluted		39,233			38,648
Basic income (loss) per share	$	0.34		$	(0.00	)
Diluted income (loss) per share	$	0.34		$	(0.00	)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The(5) followingIndebtedness table– indicates the number of shares underlying outstanding stock-based awards excluded from the computation of dilutive weighted average shares because their effect was antidilutive for the period indicated. (continued)

	Three Months Ended March 31, 2014		Nine Months Ended March 31, 2014
	(in thousands)		(in thousands)
Weighted average shares		497		1,281

Interest Expense

~~(5)~~For ~~Property~~the three months ended September 30, 2015 and ~~Equipment~~2014, interest expense consisted of the following:

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. For the three and nine months ended March 31, 2015, our ceiling test computations resulted in impairment of our oil and natural gas properties of $430.9 million and $1,113.7 million, respectively.


	Three Months Ended September 30,
	2015			2014
	(In thousands)
8.25% senior notes due 2018	$	10,519		$	10,519
Amortization of fair value premium – 8.25% senior notes		(3,441	)		(2,534	)
Revolving credit sub-facility		1,490			2,961
Promissory note payable to EGC		8,306			—
Derivative instruments premium financing and other		110			(45	)
	$	16,984		$	10,901

The(6) ceilingDerivative testFinancial computation takes into account the impact of our cash flow hedges at the end of each financial reporting period. For the three and nine months ended March 31, 2015, our ceiling test computations would have resulted in impairment of our oil and natural gas properties of $415.7 million and $1,106.0 million, respectively, had the effects of the cash flow hedges not been considered in the computation. Instruments

11We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed. Changes in fair value of these outstanding 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.

~~TABLE~~The OFfollowing ~~CONTENTS~~table sets forth our derivative instruments outstanding as of September 30, 2015.

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

(6) Asset Retirement Obligations

The following table reconciles the beginning and ending aggregate recorded amount of our asset retirement obligations.

	Nine Months Ended March 31, 2015
	(in thousands)
Beginning of period total	$	272,695
Accretion expense		17,788
Liabilities incurred and true-up to liabilities settled		2,728
Liabilities settled		(39,025	)
End of period total		254,186
Less: Current portion		(39,831	)
End of period, noncurrent portion	$	214,355

(7) Indebtedness

The following table sets forth our indebtedness.

	March 31, 2015			June 30, 2014
	(In thousands)
8.25% Senior Notes due 2018	$	542,855		$	550,566
Revolving Credit Sub-Facility		150,000			475,000
Intercompany Promissory Note		325,000			—
Derivative instruments premium financing		3,176			—
Total debt		1,021,031			1,025,566
Less: current maturities		(3,176	)		—
Total indebtedness including intercompany promissory note	$	1,017,855		$	1,025,566

Revolving Credit Sub-Facility

On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”) in connection with the issuance of $1.45 billion in aggregate principal amount of EGC’s 11.0% senior secured second lien notes due 2020 (the “11.0% Notes”). Pursuant to the terms of the Tenth Amendment, the lenders under the First Lien Credit Agreement reduced the borrowing base for EGC to $500.0 million, of which such amount $150.0 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement (“Revolving Credit Sub-Facility”). The borrowing bases are to remain effective until the next redetermination thereof under the terms of the First Lien Credit Agreement. In addition to the reduction of the borrowing base, under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement were effective:

• addition of provisions to permit 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;

TABLE OF CONTENTS

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

(7) Indebtedness – (continued)

• change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% unsecured notes due December 2017 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 the 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;

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

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

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

• addition of certain further restrictions on the prepayment and repayment of 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;

• modification to the restricted payment covenant to substantially limit the ability of EGC to make distributions and dividends to parent entities, provided that a distribution of the Grand Isle gathering system and related equipment and other assets is permitted;

• qualification on the ability of EGC and its subsidiaries to refinance outstanding indebtedness by requiring that EGC have pro forma net liquidity of $250 million at the time of such refinancing; and

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

The First Lien Credit Agreement, as amended, 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 secured leverage ratio of no more than 3.75 to 1.0. If the 8.25% Senior Note 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 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.

TABLE OF CONTENTS

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

(7) Indebtedness – (continued)

Our Revolving Credit Sub-Facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. As of March 31, 2015, EPL and EGC were in compliance with all financial covenants under the First Lien Credit Agreement, and EPL had $150.0 million in borrowings under the Revolving Credit Sub-Facility. As of March 31, 2015, we have fully utilized amounts available under our Revolving Credit Sub-Facility.

For additional information regarding our Revolving Credit Sub-Facility, see Note 8, “Indebtedness,” of our 2014 Transition Report.

Promissory Note

On March 12, 2015, in connection with EGC’s issuance of 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 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 5th, April 5th, July 5th, and October 5th, beginning September 5, 2015.

8.25% Senior Notes

The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount issued under an Indenture dated February 14, 2011 (as amended and supplemented, 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 15th and August 15th 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. The effective interest rate on the 8.25% Senior Notes is approximately 5.8%, reflecting the fair value adjustment recorded in pushdown accounting. For additional information regarding the 8.25% Senior Notes, see Note 8, “Indebtedness,” of our 2014 Transition Report.

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Sub-Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit 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 March 31, 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $3.2 million.

(8) Derivative Financial Instruments

We enter into derivative instruments to reduce exposure to fluctuations in the price of oil and natural gas for a portion of our production. Our fixed-price swaps fix the sales price for a limited amount of our production and, for the contracted volumes, eliminate our ability to benefit from increases in the sales price of the production. Derivative instruments are carried at their fair value on the consolidated balance sheets as Derivative financial instruments. Prior to the Merger, we did not designate derivative instruments as hedges, and all gains and losses due to changes in fair market value and contract settlements were recorded in Loss on derivative instruments in Other income (expense) in the condensed consolidated statements of operations.

TABLE OF CONTENTS

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

(8) Derivative Financial Instruments – (continued)

Subsequent to the Merger, we designate a majority of our derivative financial instruments as cash flow hedges. No components of the cash flow hedging instruments are excluded from the assessment of hedge ineffectiveness. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded as a loss (gain) on derivative financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled. See Note 9, “Fair Value Measurements” for information regarding fair values of our derivative instruments.

In connection with the Merger, Energy XXI assumed our existing hedges with contract terms beginning in June 2014 through December 2015. Our oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts, keeping one natural gas contract intact, and received proceeds of $4.6 million. These monetized amounts received along with a $2.9 million positive change in fair value of the monetized contracts have been recorded in stockholders’ equity as part of accumulated other comprehensive income (“AOCI”) and will be recognized in income over the contract life of the underlying hedge contracts through December 31, 2015. During the three months ended March 31, 2015, we recognized approximately $1.9 million of monetized amounts into revenues. As of March 31, 2015, we had $5.7 million of monetized amounts remaining in AOCI of which approximately $1.9 million will be recognized in income during each of the quarters ending June 30, 2015, September 30, 2015, and December 31, 2015.

During January 2015, we entered into Argus-LLS three-way collars on 7,000 barrels of our estimated oil production per day from February through December 2015.

The following table sets forth our derivative instrument outstanding as of March 31, 2015.

Oil Contracts

Type of Contract

Index

Volume (MMBtu)

Weighted Average Contract Price

Remaining Contract Term

Type of Contract

Index

Volume (MBbls)

Weighted Average Contract Price

Remaining Contract Term

Sub Floor

Floor

Ceiling

Sub Floor

Floor

Ceiling

April 2015 – December 2015

Three-Way Collars

ARGUS-LLS

1,925

32.86

45.00

75.71

October 2015 – December 2015

Three-Way Collars

ARGUS-LLS

1,012

32.73

45.00

75.45

Gas Contracts

Remaining Contract Term

Type of Contract

Index

Volume (MMBtu)

Swap Fixed Price ($4/Mmbtu)

April 2015 – December 2015

Fixed Price Swaps

NYMEX-HH

1,183

4.31

October 2015 – December 2015

Fixed Price Swaps

NYMEX-HH

369

4.31

For the three and nine months ended March 31, 2015, we reclassified from AOCI a gain of approximately $2.5 million and $27.6 million to oil and natural gas revenue, respectively. The amount expected to be reclassified from AOCI to income in the next 12 months is a gain of $6.0 million ($3.8 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions. 11

TABLE OF CONTENTS

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

(86) Derivative Financial Instruments – (continued)

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

	SUCCESSOR COMPANY						PREDECESSOR COMPANY
Gain (loss) on derivative financial instruments	Three Months Ended September 30,
	Three Months Ended March 31, 2015			Nine Months Ended March 31, 2015			Three Months Ended March 31, 2014			Nine Months Ended March 31, 2014
	2015			2014
Location of (Gain) Loss in Statement of Operations
Cash settlements, net of purchased put premium amortization	$	714		$	1,812
Cash Settlements
Change in fair value		2,064			20,045
Oil sales	$	(1,170	)	$	(25,578	)	$	—		$	—
Total gain on derivative financial instruments	$	2,778		$	21,857
Natural gas sales		(660	)		(1,328	)		—			—
Total cash settlements		(1,830	)		(26,906	)		—			—
Commodity Derivative Instruments designated as hedging instruments:
Loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		579			579			—			—
Commodity Derivative Instruments not designated as hedging instruments:
Loss on derivative financial instruments
Realized mark to market loss		—			55			(3,746	)		3,409
Unrealized mark to market loss		—			1			16,888			65,073
Total loss on derivative financial instruments		579			635			13,142			68,482
Total (gain) loss	$	(1,251	)	$	(26,271	)	$	13,142		$	68,482

We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At ~~March~~September 3130, 2015, we had no deposits for collateral with our counterparties.

(97) Fair Value Measurements

~~Fair~~Certain ~~value~~assets isand ~~the~~liabilities ~~price~~are ~~that~~measured ~~would~~at befair ~~received~~value toon ~~sell~~a anrecurring ~~asset~~basis orin ~~paid~~our toconsolidated ~~transfer~~balance asheets. ~~liability~~Valuation intechniques anare ~~orderly~~generally ~~transaction~~classified ~~between~~into ~~market~~three ~~participants~~categories: at the ~~measurement~~market ~~date.~~approach; ~~ASC~~the ~~Topic~~income ~~820,~~approach; ~~“Fair~~and ~~Value~~the ~~Measurements~~cost ~~and~~approach. ~~Disclosures,”~~The ~~establishes~~selection aand ~~fair~~application ~~value~~of ~~hierarchy~~one ~~with~~or ~~three~~more ~~levels~~of ~~based~~these ontechniques ~~the~~requires ~~reliability~~significant ofjudgment ~~the~~and ~~inputs~~is ~~used~~primarily todependent ~~determine~~upon ~~fair~~the ~~value.~~characteristics ~~These~~of ~~levels~~the ~~include:~~asset ~~Level~~or 1liability, ~~defined~~the asprincipal ~~inputs~~(or ~~such~~most asadvantageous) ~~unadjusted~~market ~~quoted~~in ~~prices~~which inparticipants ~~active~~would ~~markets~~transact for ~~identical~~the ~~assets~~asset or liability and ~~liabilities;~~the ~~Level~~quality 2,and ~~defined~~availability asof inputs. ~~other~~Inputs ~~than~~to ~~quoted~~valuation ~~prices~~techniques inare ~~active~~classified ~~markets~~as ~~that are~~ either observable ~~directly~~ or ~~indirectly observable; and Level 3, defined as~~ unobservable ~~inputs~~within ~~for~~the ~~use~~following ~~when little or no market data exists, therefore requiring an entity to develop its own assumptions.~~ hierarchy:

As• ofLevel ~~March~~1 ~~31,~~— ~~2015~~quoted ~~and~~prices ~~June~~in ~~30,~~active ~~2014,~~markets wefor ~~held~~identical ~~certain financial~~ assets ~~and~~or liabilities ~~that are required to be measured at fair value on a recurring basis, primarily our derivative financial instruments~~. 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

16• 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).

~~TABLE~~• OFLevel ~~CONTENTS~~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.

~~EPL~~For ~~OIL~~cash &and ~~GAS~~cash equivalents, ~~INC~~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. ~~AND~~For ~~SUBSIDIARIES~~the ~~NOTES~~8.25% TOSenior ~~CONDENSED~~Notes, ~~CONSOLIDATED~~the ~~FINANCIAL~~fair ~~STATEMENTS~~value ~~(UNAUDITED)~~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.

~~(9)~~Our ~~Fair~~commodity ~~Value~~derivative ~~Measurements~~instruments –consist ~~(continued)~~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

based on published LIBOR rates. The fair values of derivative financial instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of derivative financial instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. These price inputs are quoted prices for assets and liabilities similar to those held by us and meet the definition of Level 2 inputs within the fair value hierarchy. 12

~~The~~TABLE ~~following~~OF ~~table sets forth our financial assets and liabilities that are accounted for at fair value on a recurring basis.~~ CONTENTS

	March 31, 2015			June 30, 2014
	(in thousands)
Assets
Derivative financial instruments designated as hedging instruments
Current	$	5,981		$	—
Noncurrent		—			—
Total gross derivative financial instruments subject to enforceable netting agreement		5,981			—
Gross amounts offset in balance sheet		(3,075	)		—
Net amounts presented in balance sheet	$	2,906		$	—
Liabilities
Derivative financial instruments designated as hedging instruments
Current	$	3,075		$	26,440
Noncurrent		—			2,140
Total gross derivative financial instruments subject to enforceable netting agreement		3,075			28,580
Gross amounts offset in balance sheet		(3,075	)		—
Net amounts presented in balance sheet	$	—		$	28,580

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The(7) carryingFair valuesValue reportedMeasurements in– the condensed consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the short term maturities of these instruments. The fair value for the 8.25% Senior Notes 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 Sub-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. (continued)

~~The~~commodity ~~following~~derivative ~~table~~instruments ~~sets~~in ~~forth~~a ~~the~~liability ~~carrying~~position ~~values~~include ~~and~~a ~~estimated~~measure ~~fair values~~ of our ~~long~~own nonperformance risk, each based on the current published issuer-~~term~~weighted ~~indebtedness~~corporate default rates. See Note 6 — Derivative Financial Instruments.

	March 31, 2015				June 30, 2014
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% Senior Notes	$	542,855	$	379,760	$	550,566	$	545,700
Promissory Note		325,000		325,000		—		—
Revolving Credit Sub-Facility		150,000		150,000		475,000		475,000
Total	$	1,017,855	$	854,760	$	1,025,566	$	1,020,700

During the three months ended September 30, 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.


	September 30, 2015			June 30, 2015
	(in thousands)
Assets
Derivative financial instruments
Current	$	2,461		$	888
Total derivative financial instruments subject to enforceable netting agreement		2,461			888
Gross amounts offset in consolidated balance sheets		(491	)		—
Net amounts presented in consolidated balance sheets	$	1,970		$	888
Liabilities
Derivative financial instruments
Current	$	491		$	1,057
Total derivative financial instruments subject to enforceable netting agreement		491			1,057
Gross amounts offset in consolidated balance sheets		(491	)		—
Net amounts presented in consolidated balance sheets	$	—		$	1,057

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

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


	September 30, 2015				June 30, 2015
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% senior notes	$	536,018	$	138,955	$	539,459	$	306,000
Revolving credit sub-facility		150,000		150,000		150,000		150,000
Promissory note payable to EGC		325,000		325,000		325,000		325,000
Total	$	1,011,018	$	613,955	$	1,014,459	$	781,000

~~(9)~~The ~~Fair~~8.25% ~~Value~~Senior ~~Measurements~~Notes –contain ~~(continued)~~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 September 30, 2015 is not material.

The (8.25%) SeniorIncome 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 March 31, 2015 is not material. Taxes

AsWe ~~addressed~~are ina ~~Note~~(U.S.) 2,Delaware ~~“Acquisitions~~company and,” weas ~~apply~~a ~~fair~~result ~~value~~of ~~concepts~~the inMerger, ~~estimating~~a ~~and~~direct ~~allocating~~subsidiary ~~the~~of ~~fair~~EGC. ~~value~~We are a member of ~~assets~~a ~~acquired~~consolidated ~~and~~group ~~liabilities~~of ~~assumed~~corporations infor ~~acquisitions~~U.S. infederal ~~accordance~~income ~~with~~tax ~~acquisition~~purposes ~~accounting~~where ~~for~~Energy ~~business~~XXI, ~~combinations~~Inc., ~~The~~(the ~~inputs~~“U.S. toParent”) is the ~~estimated~~parent ~~fair~~entity. ~~values~~Energy XXI indirectly owns 100% of ~~assets~~U.S. ~~acquired~~Parent, ~~and~~but ~~liabilities~~is ~~assumed~~not ~~are~~a ~~described~~member of the U.S. consolidated group. We operate through our various subsidiaries in ~~Note~~the 2United States as they apply to our current ownership structure. ASC Topic 740, Income Taxes, provides that the income tax

~~(10) Income Taxes~~13

WeTABLE ~~are~~OF 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 provides that the income tax amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense/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. CONTENTS

InEPL eachOIL interim& periodGAS, we estimate the annual effective tax rate we expect to be applicable for the current fiscal year and apply it to interim periodsINC. However,AND duringSUBSIDIARIES theNOTES firstTO quarterCONSOLIDATED ofFINANCIAL fiscalSTATEMENTS year 2015, we recorded a goodwill impairment charge of $329 million (see Note 3 — Pushdown Accounting and GoodwillUNAUDITED). Currently, our estimated annual effective tax/(benefit) rate is approximately (36.2)% excluding the effect of the goodwill impairment charge. For purposes of computing our interim provision (benefit) for income taxes, the goodwill impairment charge was treated as a discrete item in the quarter in which it occurred. Our actual effective tax/(benefit) rates for the three and nine months ended March 31, 2015 were (38.0)% and (28.6)%, respectively. The variance from the U.S. statutory rate of 35% is primarily due to two elements: (i) the impairment of goodwill during the first quarter of fiscal year 2015 and (ii) an increase to the statutory rate due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses and state income taxes).

We have not recorded a valuation allowance against net deferred tax assets to date as we believe that, more-likely-than-not, at March 31, 2015, we will generate sufficient future taxable income from the reversal of existing temporary differences (primarily related to the excess of book carrying value of oil and natural gas properties8) overIncome theirTaxes tax– bases; however, with (continued weakness in commodity pricing, this judgment could change as early as the fourth quarter of fiscal 2015. )

~~(11)~~amounts ~~Related~~presented ~~Party~~in ~~Transactions~~the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense/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.

OnWe ~~June~~estimate 3,the ~~2014,~~annual weeffective ~~entered~~tax anrate ~~intercompany~~for ~~services~~the ~~and~~current ~~cost~~fiscal ~~allocation~~year ~~agreement~~and ~~with~~apply ~~Energy~~it ~~XXI~~to ~~Services~~interim periods. Currently, ~~LLC~~our estimated annual effective tax/(~~“Energy~~benefit) ~~Services”~~rate is zero. Our actual effective tax/(benefit) rate for the three months ended September 30, an2015 ~~affiliate~~was ofalso zero. The variance from the ~~Company~~U.S. ~~Services~~statutory ~~provided~~rate byof ~~Energy~~35% ~~Services~~is ~~include~~primarily ~~management,~~due ~~legal,~~to ~~accounting,~~continued ~~tax,~~recorded ~~corporate~~and ~~secretarial~~forecast losses that, ~~human~~based ~~resources~~on present circumstances, ~~employee~~will not result in us recording a current income tax benefit. ~~administration~~Rather, ~~office~~all ~~space~~increases ~~and~~in ~~other~~net ~~furniture~~deferred ~~and~~tax ~~equipment~~assets ~~management,~~(primarily ~~and~~related ~~other~~to ~~support~~net ~~services.~~operating ~~Cost~~loss (“NOL”) carryovers net of ~~these~~deferred ~~services~~tax ~~for~~liability from ~~the~~oil ~~three~~and ~~months~~natural ~~ended~~gas ~~March~~properties’ ~~31,~~net ~~2015~~book ~~was~~carrying ~~approximately~~values ~~$14.0~~exceeding ~~million,~~their ofcorresponding ~~which~~tax ~~approximately~~bases) ~~$10.4~~will ~~million~~be iscompletely ~~included~~offset inby ~~general~~increases ~~and~~in ~~administrative~~valuation ~~expense~~allowances. ~~Cost~~As ofrequired ~~these~~by ~~services~~ASC Topic 740-270, Income Taxes: Interim Reporting, we forecast our tax position for the ~~nine~~ ~~months~~year, ~~ended~~and ~~March~~may ~~31,~~not ~~2015~~record ~~was~~an ~~approximately~~additional ~~$23~~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.8 ~~million~~At this time, we do not have such a belief (due to a preponderance of ~~which~~negative ~~approximately~~evidence ~~$19~~as to future realizability) and accordingly reflect a current deferred tax benefit of zero.5 ~~million~~We iscontinue ~~included~~to inevaluate ~~general~~the need for the valuation allowance based on current and ~~administrative~~expected ~~expense~~earnings and other factors, and adjust it accordingly.

~~TABLE~~On OFJune ~~CONTENTS~~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 months ended September 30, 2015 was approximately $9.3 million, of which approximately $7.5 million is included in general and administrative expense. Cost of these services for the three months ended September 30, 2014 was approximately $4.0 million, of which approximately $3.7 million is included in general and administrative expense.

~~EPL~~On ~~OIL~~March &12, ~~GAS~~2015, ~~INC~~in connection with EGC’s issuance of the 11.0% ~~AND~~Notes, ~~SUBSIDIARIES~~we ~~NOTES~~entered TOinto ~~CONDENSED~~the ~~CONSOLIDATED~~Promissory ~~FINANCIAL~~Note ~~STATEMENTS~~with ~~(UNAUDITED)~~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. Interest expense on the Promissory Note amounted to approximately $8.3 million for the three months ended September 30, 2015. See Note 5 — Indebtedness for more information regarding the Promissory Note.

(1110) RelatedCommitments Partyand Transactions – (continued)Contingencies

OnLitigation. We ~~March~~are ~~12,~~involved ~~2015,~~ in ~~connection~~various ~~with~~legal ~~EGC’s~~proceedings ~~issuance~~and ~~of the 11.0% Notes~~claims, wewhich ~~entered~~arise ~~into~~in the ~~Promissory~~ordinary ~~Note~~course ~~with a face value~~ of ~~$325~~our ~~million~~business. ~~The~~We ~~Promissory~~do ~~Note~~not ~~bears~~believe ~~interest~~the atultimate anresolution ~~annual rate~~ of ~~10%,~~any ~~has~~such aactions ~~maturity~~will ~~date~~have ~~of October 9, 2018, and is secured by~~ a ~~second~~material ~~priority~~effect ~~lien~~ on ~~certain of~~ our ~~assets~~consolidated ~~that~~financial ~~secure the obligations under the First Lien Credit Agreement. Interest expense on the Promissory Note amounted to approximately $1.6 million for the three months ended March 31~~position, ~~2015.~~results ~~See~~of ~~Note~~operations 7,or ~~“Indebtedness”~~cash ~~for more information regarding the Promissory Note~~flows.

Performance Bonds. As of September 30, 2015, we had $180.8 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 (12OCS), ~~Commitments~~approximately $58.3 million of our performance bonds are lease and/or ~~Contingencies~~area bonds issued to the Bureau of Ocean Energy Management (“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

Litigation. We are a defendant in a number of lawsuits and are involved in governmental and regulatory proceedings, all of which arose in the ordinary course of business, including, but not limited to, personal injury claims, royalty claims, contract claims, and environmental claims, including claims involving assets owned by acquired companies. While the ultimate outcome and impact on us cannot be predicted with certainty, management believes that the resolution of pending proceedings will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows. 14

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

PlaintiffsEPL allegedOIL a& variety of causes of action challenging the Agreement and Plan of Merger between Energy XXIGAS, OpCo, Merger Sub, and EPL, which provided for the acquisition of EPL by Energy XXIINC. PlaintiffsAND allegedSUBSIDIARIES thatNOTES (a)TO ourCONSOLIDATED directorsFINANCIAL allegedlySTATEMENTS breached fiduciary duties in connection with the Merger and (bUNAUDITED) we along with Energy XXI, OpCo, and Merger Sub allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the Merger Agreement rescinded and also sought damages and attorneys’ fees.

On(10) JanuaryCommitments 16,and 2015,Contingencies Plaintiffs– filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice. (continued)

~~Other~~facilities. We ~~maintain~~In ~~restricted~~April ~~escrow~~2015, ~~funds~~we inreceived aletters ~~trust~~from ~~for~~the ~~future~~BOEM ~~abandonment~~stating ~~costs~~that atcertain of our ~~East~~subsidiaries ~~Bay~~no ~~property~~longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The ~~trust~~letters ~~was~~notified ~~originally~~us ~~funded~~that ~~with~~certain of our subsidiaries must provide approximately $15566.05 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, ~~with~~rights-of-way, ~~accumulated~~and ~~interest~~rights-of-use and easements. In June 2015, ~~increased~~we reached agreements with the BOEM pursuant to which we provided $1654.7 million atof ~~December~~supplemental ~~31,~~bonds ~~2008.~~issued Weto ~~may~~the ~~draw~~BOEM ~~from~~(which is reflected in the ~~trust~~$58.3 ~~upon~~million ~~completion~~in oflease ~~qualifying~~and/or ~~abandonment~~area ~~activities~~bonds atdiscussed ~~our~~above), ~~East~~and ~~Bay~~the ~~field.~~BOEM Atagreed ~~March~~to ~~31,~~withdraw ~~2015,~~its weorders ~~had~~with ~~$6.0~~regard ~~million~~to ~~remaining~~supplemental inbonding ~~restricted~~and ~~escrow~~postpone ~~funds~~until ~~for~~November ~~decommissioning~~15, ~~work~~2015 inthe ~~our~~issuance ~~East~~of ~~Bay~~further ~~field,~~requirements ~~which~~of ~~will~~us ~~remain~~related ~~restricted~~to ~~until~~these ~~substantially~~supplemental ~~all~~financial ~~required~~assurance ~~decommissioning~~and/or inbonding obligations. On June 30, 2015, we sold the East Bay field, isand ~~complete~~as a result, the $566.5 ~~Amounts~~million onof ~~deposit~~requested insupplemental ~~the trust~~financial ~~account~~assurance ~~are~~and/or ~~reflected~~bonding required by the BOEM in ~~Restricted~~April ~~cash~~2015 onwas ~~our~~reduced ~~condensed~~by ~~consolidated~~approximately ~~balance~~$178 ~~sheets~~million.

WeSince ~~record~~our ~~liabilities~~June ~~when~~2015 weagreements ~~deliver~~with ~~production~~the ~~that~~BOEM, iswe inhave ~~excess~~worked oftowards ~~our~~preparing ~~interest~~a inlong-term ~~certain~~financial ~~properties.~~assurance Inplan ~~addition~~that towe ~~these~~could ~~imbalances,~~submit weto ~~may,~~the ~~from~~BOEM ~~time~~for toapproval. ~~time,~~We behave ~~allocated~~held ~~cash~~meetings ~~sales~~with ~~proceeds~~the BOEM in ~~excess~~furtherance of ~~amounts~~the ~~that~~plan’s wedevelopment ~~estimate~~and, ~~are~~while ~~due~~a toversion usof ~~for~~the ~~our~~long-term ~~interest~~financial inassurance ~~production.~~plan ~~These~~could ~~allocations~~be ~~may~~submitted beby ~~subject~~November 15, 2015, we are currently seeking a 30-day extension to ~~further~~the ~~review~~November 15, ~~may~~2015 ~~require~~date ~~more~~in ~~information~~order to ~~resolve~~augment orthe ~~may~~final beplan in ~~dispute~~light of new information received.

WeIn ~~and~~October ~~our~~2015, ~~oil~~we ~~and~~received ~~gas~~information ~~joint~~from ~~interest~~the ~~owners~~BOEM ~~are~~indicating ~~subject~~that, tofollowing ~~periodic~~November ~~audits~~15, 2015, we may receive additional demands of supplemental financial assurance for amounts in addition to the ~~joint~~$566.5 ~~interest~~million ~~accounts~~initially ~~for~~sought ~~leases~~by the BOEM in ~~which~~April we2015, ~~participate~~primarily ~~and/or~~relating ~~operate.~~to Ascertain properties that are no longer exempt from supplemental bonding as a result of ~~these~~co-owners ~~joint~~losing ~~interest~~their ~~audits,~~exemptions. ~~amounts~~We ~~payable~~believe orthat ~~receivable~~a bysubstantial usportion ~~for~~of ~~costs~~the ~~incurred~~additional supplemental financial assurance and/or ~~revenue~~bonding ~~distributed~~that may be sought by the ~~operator~~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, onand leases where we are not the permitted operator and no drilling of wells has occurred. Our request for a ~~lease~~30-day ~~may~~extension befrom ~~adjusted~~the November 15, ~~resulting~~2015 date for submittal of the long-term financial assurance plan is in ~~adjustments~~part to give us time to evaluate and address these potential additional liabilities. We would expect that most, ~~increases~~if ornot ~~decreases~~all, toof our ~~net~~co-lessees ~~costs~~with orthe ~~revenues~~remaining ~~and~~working ~~the~~interest ~~related~~in ~~cash~~such ~~flows.~~lease ~~Such~~interests will provide their share of the bonding.

19Consequently, 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 after November 15, 2015 if these items are not otherwise addressed in our long-term financial assurance plan. If we are successful in obtaining the 30-day extension, we intend for our long-term financial assurance plan to address these additional financial assurance requirements for which we received information in October 2015. Please note 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.

~~TABLE~~Unrelated OFto ~~CONTENTS~~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

~~EPL OIL & GAS, INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)~~15

~~(12)~~TABLE ~~Commitments~~OF ~~and Contingencies – (continued)~~CONTENTS

adjustmentsEPL mayOIL be& material. When they occurGAS, theseINC. adjustmentsAND areSUBSIDIARIES recordedNOTES inTO theCONSOLIDATED currentFINANCIAL period,STATEMENTS which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. (UNAUDITED)

Subsequent Event. In April 2015, we received letters from the Bureau of Ocean Energy Management (the “BOEM”10) statingCommitments that we no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonmentContingencies liabilities.– The letters notified us that we must provide supplemental financial assurance and/or bonding for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $566.5 million, which amount is currently being negotiated by us. We are currently evaluating the impact of these BOEM letters on our future consolidated financial position, results of operations and cash flow. (continued)

~~(13)~~tailored ~~Supplemental~~plan. ~~Condensed~~Furthermore, ~~Consolidating~~with ~~Financial~~issuance ~~Information~~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.

InWhile ~~connection with issuing~~ the ~~8.25%~~Draft ~~Senior~~Guidance, ~~Notes~~once ~~described~~implemented inby ~~Note~~the 7BOEM, ~~“Indebtedness,”~~would ~~all~~allow ofan ~~our~~increased ~~existing~~number ~~direct~~of ~~and~~operators ~~indirect domestic subsidiaries~~ (~~other~~relative ~~than~~to ~~immaterial~~those ~~subsidiaries)~~operators ~~each~~under ofthe ~~which~~existing isNotice ~~100%~~to ~~owned~~Lessees ~~by EPL~~ (~~the~~ “~~Guarantor Subsidiaries~~NTL”), ~~jointly~~regarding ~~and~~supplemental ~~severally~~financial ~~guaranteed~~assurance ~~the payment obligations under our 8.25% Senior Notes. The guarantees are full~~ and ~~unconditional,~~bonding) asto ~~those terms are used in Rule 3~~self-10insure offor ~~Regulation~~their ~~S-X,~~decommissioning ~~except~~liabilities that ais ~~Guarantor~~no ~~Subsidiary~~more ~~can~~than be10% ~~automatically released and relieved~~ of ~~its~~their ~~obligations~~tangible ~~under~~net ~~certain customary circumstances contained in the 2011 Indenture. So long as other applicable provisions of the indenture are adhered to~~worth, ~~these~~there ~~customary circumstances include: when a Guarantor Subsidiary~~ is ~~declared~~no ~~“unrestricted”~~assurance ~~for~~that ~~covenant purposes, when~~ the ~~requirements~~BOEM ~~for~~will ~~legal~~allow ~~defeasance~~us ~~or covenant defeasance or~~ to ~~discharge~~utilize ~~the~~self-insurance ~~indenture~~programs ~~have~~and ~~been~~we ~~satisfied,~~currently ordo ~~when~~not ~~the~~plan 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~~self-insurance ~~(Parent~~under ~~Company Only) and for~~ the ~~Guarantor~~long-term ~~Subsidiaries. We have not presented separate~~ financial ~~statements~~assurance ~~and~~plan ~~other disclosures concerning the Guarantor Subsidiaries, or for any individual Guarantor Subsidiary, because management has determined~~ that ~~such~~we ~~information~~plan isto ~~not~~submit ~~material~~ to ~~investors~~the BOEM.

~~The~~In addition to the Draft Guidance describing revised supplemental ~~condensed~~bonding ~~consolidating~~procedures ~~financial~~that ~~information~~may ~~has~~be ~~been~~used ~~prepared~~by ~~pursuant~~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 ~~rules~~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 ~~for~~applicable ~~condensed~~to us or our subsidiaries’ properties could materially and adversely affect our financial ~~information~~condition, cash flows, and ~~does~~results ~~not~~of ~~include~~operations. ~~all~~In ~~disclosures~~addition, ~~included~~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 credit facility and would reduce the amount of borrowings available under such facility in ~~annual~~the ~~financial~~amount ~~statements~~of any such letter of credit obligations. ~~The~~We ~~principal~~can ~~eliminating~~provide ~~entries~~no ~~eliminate~~assurance ~~investments~~that we can continue to obtain bonds or other surety in ~~subsidiaries~~all cases or that we will have sufficient availability under our 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 terminated, and ~~intercompany~~such ~~balances~~action could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

20Other. We maintain restricted escrow funds as required by certain contractual arrangements. At September 30, 2015, our restricted cash included $21 million related to the East Bay sale which will remain restricted until our next borrowing base redetermination 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.

~~TABLE~~We OFand ~~CONTENTS~~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.

SUCCESSOR(11) COMPANY Supplemental Condensed Consolidating BalanceFinancial Sheet As of March 31, 2015 (UNAUDITED)Information

	Parent Company Only			Guarantor Subsidiaries		Reclassifications & Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	95		$	—	$	—		$	95
Trade accounts receivable – net		54,029			—		(37	)		53,992
Intercompany receivables		—			20,213		(20,213	)		—
Derivative financial instruments		2,906			—		—			2,906
Deferred tax asset		16,760			—		—			16,760
Prepaid expenses		6,135			—		—			6,135
Total current assets		79,925			20,213		(20,250	)		79,888
Net property and equipment		1,893,726			159,808		—			2,053,534
Investment in affiliates		129,065			—		(129,065	)		—
Restricted cash		6,024			—		—			6,024
Other assets		1,069			89		(90	)		1,068
Total assets	$	2,109,809		$	180,110	$	(149,405	)	$	2,140,514
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	30,011		$	424	$	(37	)	$	30,398
Due to EGC		182,792			—		—			182,792
Intercompany payables		20,213			—		(20,213	)		—
Accrued liabilities		72,487			—		(90	)		72,397
Asset retirement obligations		34,627			5,204		—			39,831
Current maturities of long-term debt		3,176			—		—			3,176
Total current liabilities		343,306			5,628		(20,340	)		328,594
Long-term debt		692,855			—		—			692,855
Intercompany promissory note		325,000			—		—			325,000
Asset retirement obligations		172,705			41,650		—			214,355
Deferred tax liabilities		45,541			3,767		—			49,308
Total liabilities		1,579,407			51,045		(20,340	)		1,610,112
Stockholder’s equity:
Preferred stock		—			—		—			—
Common stock		—			—		—			—
Additional paid-in capital		1,599,341			85,479		(85,479	)		1,599,341
Accumulated other comprehensive income		3,790			—		—			3,790
Retained earnings (accumulated deficit)		(1,072,729	)		43,586		(43,586	)		(1,072,729	)
Total stockholder’s equity		530,402			129,065		(129,065	)		530,402
Total liabilities and stockholder’s equity	$	2,109,809		$	180,110	$	(149,405	)	$	2,140,514

In connection with issuing the 8.25% Senior Notes described in Note 5 — 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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SUCCESSOREPL COMPANYOIL Supplemental& CondensedGAS, ConsolidatingINC. BalanceAND SheetSUBSIDIARIES AsNOTES ofTO JuneCONSOLIDATED 30,FINANCIAL 2014STATEMENTS (AUDITEDUNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Reclassifications & Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	5,601		$	—	$	—		$	5,601
Trade accounts receivable – net		72,156			145		—			72,301
Intercompany receivables		—			26,311		(26,311	)		—
Deferred tax asset		24,587			—		—			24,587
Prepaid expenses		26,521			—		—			26,521
Total current assets		128,865			26,456		(26,311	)		129,010
Net property and equipment		3,034,805			170,382		—			3,205,187
Investment in affiliates		126,638			—		(126,638	)		—
Goodwill		329,293			—		—			329,293
Restricted cash		6,023			—		—			6,023
Other assets		226			91		—			317
Total assets	$	3,625,850		$	196,929	$	(152,949	)	$	3,669,830
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	92,325		$	656	$	—		$	92,981
Due to EGC		4,960			—		—			4,960
Intercompany payables		26,311			—		(26,311	)		—
Accrued liabilities		161,503			15		—			161,518
Asset retirement obligations		33,357			6,474		—			39,831
Derivative financial instruments		26,440			—		—			26,440
Total current liabilities		344,896			7,145		(26,311	)		325,730
Long-term debt		1,025,566			—		—			1,025,566
Asset retirement obligations		193,908			38,956		—			232,864
Deferred tax liabilities		459,608			24,190		—			483,798
Derivative financial instruments		2,140			—		—			2,140
Other		6			—		—			6
Total liabilities		2,026,124			70,291		(26,311	)		2,070,104
Stockholder’s equity:
Preferred stock		—			—		—			—
Common stock		—			—		—			—
Additional paid-in capital		1,599,341			85,479		(85,479	)		1,599,341
Accumulated other comprehensive loss		(6,252	)		—		—			(6,252	)
Retained earnings		6,637			41,159		(41,159	)		6,637
Total stockholder’s equity		1,599,726			126,638		(126,638	)		1,599,726
Total liabilities and stockholder’s equity	$	3,625,850		$	196,929	$	(152,949	)	$	3,669,830

(11) Supplemental Condensed Consolidating Financial Information – (continued)

22defeasance 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.

~~TABLE~~The OFsupplemental ~~CONTENTS~~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.

~~SUCCESSOR COMPANY Supplemental Condensed Consolidating Statement of Operations Three Months Ended March 31, 2015 (UNAUDITED)~~17

	Parent Company Only			Guarantor Subsidiaries			Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	79,065		$	8,188		$	—		$	87,253
Total revenue		79,065			8,188			—			87,253
Costs and expenses:
Lease operating		49,552			19			—			49,571
Transportation		544			(1	)		—			543
Impairment of oil and natural gas properties		430,859			—			—			430,859
Depreciation, depletion and amortization		68,541			5,035			—			73,576
Accretion of liability for asset retirement obligations		4,328			1,181			—			5,509
General and administrative		11,998			—			—			11,998
Taxes, other than on earnings		2,193			864			—			3,057
Other		(3	)		—			—			(3	)
Total costs and expenses		568,012			7,098			—			575,110
Income (loss) from operations		(488,947	)		1,090			—			(487,857	)
Other income (expense):
Interest income		6			—			—			6
Interest expense		(12,558	)		—			—			(12,558	)
Loss on derivative instruments		(579	)		—			—			(579	)
Income from equity investments		716			—			(716	)		—
Total other expense		(12,415	)		—			(716	)		(13,131	)
Income (loss before provision for income taxes)		(501,362	)		1,090			(716	)		(500,988	)
Income tax expense (benefit)		(190,845	)		374			—			(190,471	)
Net income (loss)	$	(310,517	)	$	716		$	(716	)	$	(310,517	)
Comprehensive income (loss)
Net income (loss)		(310,517	)		716			(716	)		(310,517	)
Other comprehensive loss		(2,182	)		—			—			(2,182	)
Comprehensive income (loss)	$	(312,699	)	$	716		$	(716	)	$	(312,699	)

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23EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance Sheet As of September 30, 2015 (UNAUDITED)

TABLE OF CONTENTS


	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	—		$	—	$	—		$	—
Trade accounts receivable – net		55,146			—		—			55,146
Intercompany receivables		—			127,756		(127,756	)		—
Fair value of commodity derivative instruments		1,970			—		—			1,970
Restricted cash		6,025			—		—			6,025
Prepaid expenses		1,523			—		—			1,523
Total current assets		64,664			127,756		(127,756	)		64,664
Net property and equipment		1,051,005			2,949		—			1,053,954
Restricted cash		21,008			—		—			21,008
Investment in affiliates		130,705			—		(130,705	)		—
Other assets		947			—		—			947
Total assets	$	1,268,329		$	130,705	$	(258,461	)	$	1,140,573
LIABILITIES AND STOCKHOLDER'S DEFICIT
Current liabilities:
Accounts payable	$	42,797		$	—	$	—		$	42,797
Due to EGC		190,401			—		—			190,401
Intercompany payables		127,756			—		(127,756	)		—
Accrued liabilities		71,550			—		—			71,550
Asset retirement obligations		15,839			—		—			15,839
Current maturities of long-term debt		1,684			—		—			1,684
Total current liabilities		450,027			—		(127,756	)		322,271
Long-term debt		686,018			—		—			686,018
Promissory note payable to EGC		325,000			—		—			325,000
Asset retirement obligations		196,004			—		—			196,004
Total liabilities		1,657,049			—		(127,756	)		1,529,293
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)		(1,988,061	)		45,226		(45,226	)		(1,988,061	)
Total stockholder's equity (deficit)		(388,720	)		130,705		(130,705	)		(388,720	)
Total liabilities and stockholder's equity (deficit)	$	1,268,329		$	130,705	$	(258,461	)	$	1,140,573

~~SUCCESSOR COMPANY Supplemental Condensed Consolidating Statement of Operations Nine Months Ended March 31, 2015 (UNAUDITED)~~18

	Parent Company Only			Guarantor Subsidiaries		Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	379,502		$	37,541	$	—		$	417,043
Other		778			154		—			932
Total revenue		380,280			37,695		—			417,975
Costs and expenses:
Lease operating		152,170			9,005		—			161,175
Transportation		2,316			1		—			2,317
Impairment of oil and natural gas properties		1,113,727			—		—			1,113,727
Goodwill impairment		329,293			—		—			329,293
Depreciation, depletion and amortization		218,928			16,940		—			235,868
Accretion of liability for asset retirement obligations		14,580			3,208		—			17,788
General and administrative		26,850			—		—			26,850
Taxes, other than on earnings		2,792			4,737		—			7,529
Other		18			—		—			18
Total costs and expenses		1,860,674			33,891		—			1,894,565
Income (loss) from operations		(1,480,394	)		3,804		—			(1,476,590	)
Other income (expense):
Interest income		10			—		—			10
Interest expense		(34,406	)		—		—			(34,406	)
Loss on derivative instruments		(635	)		—		—			(635	)
Income from equity investments		2,427			—		(2,427	)		—
Total other expense		(32,604	)		—		(2,427	)		(35,031	)
Income (loss) before provision for income taxes		(1,512,998	)		3,804		(2,427	)		(1,511,621	)
Income tax expense (benefit)		(433,632	)		1,377		—			(432,255	)
Net income (loss)	$	(1,079,366	)	$	2,427	$	(2,427	)	$	(1,079,366	)
Comprehensive income (loss)
Net income (loss)		(1,079,366	)		2,427		(2,427	)		(1,079,366	)
Other comprehensive income		10,042			—		—			10,042
Comprehensive income (loss)	$	(1,069,324	)	$	2,427	$	(2,427	)	$	(1,069,324	)

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24EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance Sheet As of June 30, 2015 (AUDITED)

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	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
Net property and equipment		1,412,076			2,949		—			1,415,025
Investment in affiliates		130,705			—		(130,705	)		—
Other assets		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

~~PREDECESSOR COMPANY Supplemental Condensed Consolidating Statement of Operations Three Months Ended March 31, 2014 (UNAUDITED)~~19

	Parent Company Only			Guarantor Subsidiaries		Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	141,812		$	16,658	$	—		$	158,470
Other		264			757		—			1,021
Total revenue		142,076			17,415		—			159,491
Costs and expenses:
Lease operating		35,736			5,998		—			41,734
Transportation		899			1		—			900
Exploration expenditures and dry hole costs		4,941			—		—			4,941
Impairment of oil and natural gas properties		61			—		—			61
Depreciation, depletion and amortization		40,696			4,949		—			45,645
Accretion of liability for asset retirement obligations		5,788			1,209		—			6,997
General and administrative		10,287			—		—			10,287
Taxes, other than on earnings		177			2,295		—			2,472
Other		(942	)		—		—			(942	)
Total costs and expenses		97,643			14,452		—			112,095
Income from operations		44,433			2,963		—			47,396
Other income (expense):
Interest income		10			—		—			10
Interest expense		(13,304	)		—		—			(13,304	)
Loss on derivative instruments		(13,142	)		—		—			(13,142	)
Income from equity investments		1,884			—		(1,884	)		—
Total other expense		(24,552	)		—		(1,884	)		(26,436	)
Income before provision for income taxes		19,881			2,963		(1,884	)		20,960
Income tax expense		6,550			1,079		—			7,629
Net income	$	13,331		$	1,884	$	(1,884	)	$	13,331

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25EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Operations Three Months Ended September 30, 2015 (UNAUDITED)

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	Parent Company Only			Guarantor Subsidiaries		Eliminations		Consolidated
	(In thousands)
Revenues
Oil sales	$	73,372		$	—	$	—	$	73,372
Natural gas sales		12,618			—		—		12,618
Gain on derivative instruments		2,778			—		—		2,778
Total revenues		88,768			—		—		88,768
Costs and expenses
Lease operating		26,153			—		—		26,153
Transportation		723			—		—		723
Depreciation, depletion and amortization		57,660			—		—		57,660
Accretion of asset retirement obligations		6,741			—		—		6,741
Impairment of oil and natural gas properties		308,078			—		—		308,078
General and administrative		7,944			—		—		7,944
Taxes, other than on earnings		(935	)		—		—		(935	)
Total costs and expenses		406,364			—		—		406,364
Income (loss) from operations		(317,596	)		—		—		(317,596	)
Other income (expense):
Interest income		12			—		—		12
Interest expense		(16,984	)		—		—		(16,984	)
Income from equity investments		—			—		—		—
Total other expense, net		(16,972	)		—		—		(16,972	)
Income (loss) before income taxes		(334,568	)		—		—		(334,568	)
Income tax expense		—			—		—		—
Net income (loss)	$	(334,568	)	$	—	$	—	$	(334,568	)

~~PREDECESSOR COMPANY Supplemental Condensed Consolidating Statement of Operations Nine Months Ended March 31, 2014 (UNAUDITED)~~20

	Parent Company Only			Guarantor Subsidiaries		Reclassifications & Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	424,970		$	58,259	$	—		$	483,229
Other		543			2,321		—			2,864
Total revenue		425,513			60,580		—			486,093
Costs and expenses:
Lease operating		105,136			18,067		—			123,203
Transportation		3,123			2		—			3,125
Exploration expenditures and dry hole costs		22,415			618		—			23,033
Impairment of oil and natural gas properties		827			—		—			827
Depreciation, depletion and amortization		129,764			16,382		—			146,146
Accretion of liability for asset retirement obligations		19,033			4,065		—			23,098
General and administrative		23,923			—		—			23,923
Taxes, other than on earnings		638			7,725		—			8,363
Gain on sale of assets		(1,825	)		—		—			(1,825	)
Other		27,330			127		—			27,457
Total costs and expenses		330,364			46,986		—			377,350
Income from operations		95,149			13,594		—			108,743
Other income (expense):
Interest income		82			—		—			82
Interest expense		(39,479	)		—		—			(39,479	)
Loss on derivative instruments		(68,482	)		—		—			(68,482	)
Income from equity investments		8,633			—		(8,633	)		—
Total other expense		(99,246	)		—		(8,633	)		(107,879	)
Income (loss) before provision for income taxes		(4,097	)		13,594		(8,633	)		864
Income tax expense (benefit)		(4,086	)		4,961		—			875
Net income (loss)	$	(11	)	$	8,633	$	(8,633	)	$	(11	)

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26EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Operations Three Months Ended September 30, 2014 (UNAUDITED)

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	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenues
Oil sales	$	140,715		$	17,601	$	—		$	158,316
Natural gas sales		13,857			97					13,954
Gain on derivative instruments		21,857			—		—			21,857
Total revenues		176,429			17,698		—			194,127
Costs and expenses
Lease operating		52,574			3,726		—			56,300
Transportation		624			1		—			625
Depreciation, depletion and amortization		68,005			5,740		—			73,745
Accretion of asset retirement obligations		5,343			838		—			6,181
Goodwill impairment		329,293			—		—			329,293
General and administrative		8,042			—		—			8,042
Taxes, other than on earnings		105			2,423		—			2,528
Other		21			—		—			21
Total costs and expenses		464,007			12,728		—			476,735
Income (loss) from operations		(287,578	)		4,970		—			(282,608	)
Other income (expense):
Interest expense		(10,901	)		—		—			(10,901	)
Income from equity investments		3,134			—		(3,134	)		—
Total other expense, net		(7,767	)		—		(3,134	)		(10,901	)
Income (loss) before income taxes		(295,345	)		4,970		(3,134	)		(293,509	)
Income tax expense		11,011			1,836		—			12,847
Net income (loss)	$	(306,356	)	$	3,134	$	(3,134	)	$	(306,356	)

~~SUCCESSOR COMPANY Supplemental Condensed Consolidating Statement of Cash Flows Nine Months Ended March 31, 2015 (UNAUDITED)~~21

	Parent Company Only			Guarantor Subsidiaries			Reclassifications & Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	83,979		$	6,365		$	—	$	90,344
Cash flows used in investing activities:
Property acquisitions		(350	)		—			—		(350	)
Capital expenditures		(265,131	)		(6,365	)		—		(271,496	)
Other property and equipment additions		(58	)		—			—		(58	)
Net cash used in investing activities		(265,539	)		(6,365	)		—		(271,904	)
Cash flows provided by financing activities:
Repayments of indebtedness		(325,000	)		—			—		(325,000	)
Proceeds from intercompany promissory note		325,000								325,000
Advances from EGC		177,832			—			—		177,832
Deferred financing costs		(1,089	)		—			—		(1,089	)
Other		(689	)		—			—		(689	)
Net cash provided by financing activities		176,054			—			—		176,054
Net decrease in cash and cash equivalents		(5,506	)		—			—		(5,506	)
Cash and cash equivalents at beginning of period		5,601			—			—		5,601
Cash and cash equivalents at end of period	$	95		$	—		$	—	$	95

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27EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash Flows Three Months Ended September 30, 2015 (UNAUDITED)

TABLE OF CONTENTS


	Parent Company Only			Guarantor Subsidiaries		Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	15,936		$	—	$	—	$	15,936
Cash flows used in investing activities:
Capital expenditures		(13,120	)		—		—		(13,120	)
Net cash used in investing activities		(13,120	)		—		—		(13,120	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt		(1,698	)		—		—		(1,698	)
Cash restricted under revolving credit facility related to property sold		(21,008	)		—		—		(21,008	)
Advances from EGC		19,673			—		—		19,673
Net cash used in financing activities		(3,033	)		—		—		(3,033	)
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	$	—		$	—	$	—	$	—

~~PREDECESSOR COMPANY Supplemental Condensed Consolidating Statement of Cash Flows Nine Months Ended March 31, 2014 (UNAUDITED)~~22

	Parent Company Only			Guarantor Subsidiaries			Reclassifications & Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	235,046		$	22,977		$	—	$	258,023
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		51,757			—			—		51,757
Property acquisitions		(83,412	)		—			—		(83,412	)
Deposit for Nexen Acquisition		(7,040	)		—			—		(7,040	)
Capital expenditures		(245,928	)		(22,977	)		—		(268,905	)
Other property and equipment additions		(984	)		—			—		(984	)
Proceeds from sale of assets		80			—			—		80
Net cash used in investing activities		(285,527	)		(22,977	)		—		(308,504	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		55,000			—			—		55,000
Deferred financing costs		(206	)		—			—		(206	)
Purchase of shares into treasury		(4,544	)		—			—		(4,544	)
Exercise of stock options		794			—			—		794
Net cash provided by financing activities		51,044			—			—		51,044
Net increase in cash and cash equivalents		563			—			—		563
Cash and cash equivalents at beginning of period		3,885			—			—		3,885
Cash and cash equivalents at end of period	$	4,448		$	—		$	—	$	4,448

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28EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash Flows Three Months Ended September 30, 2014 (UNAUDITED)

TABLE OF CONTENTS


	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	58,897		$	3,951		$	—	$	62,848
Cash flows used in investing activities:
Property acquisitions		(260	)		—			—		(260	)
Capital expenditures		(107,185	)		(3,951	)		—		(111,136	)
Other property and equipment additions		(40	)		—			—		(40	)
Net cash used in investing activities		(107,485	)		(3,951	)		—		(111,436	)
Cash flows provided by financing activities:
Advances from EGC		43,010			—			—		43,010
Net cash provided by financing activities		43,010			—			—		43,010
Net decrease in cash and cash equivalents		(5,578	)		—			—		(5,578	)
Cash and cash equivalents at beginning of period		5,601			—			—		5,601
Cash and cash equivalents at end of period	$	23		$	—		$	—	$	23

~~Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.~~23

~~Statements~~TABLE weOF 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 “Risk Factors” in Items 1 and 1A of Part I of our 2014 Transition Report and under the heading “Risk Factors” in Item 1A of Part II of this Quarterly Report. CONTENTS

~~OVERVIEW~~Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

~~EPL~~Statements ~~Oil~~we &make ~~Gas,~~in ~~Inc.~~this ~~(“we,”~~quarterly ~~“our,”~~report ~~“us,”~~on ~~“the~~Form ~~Company”~~10-Q or(the “~~EPL~~Quarterly Report”) ~~was~~which ~~incorporated~~express as a ~~Delaware~~belief, ~~corporation~~expectation inor ~~January~~intention, ~~1998~~as ~~and~~well isas athose ~~wholly-owned~~that ~~subsidiary~~are ofnot ~~Energy~~historical ~~XXI Gulf Coast~~fact, ~~Inc.~~may ~~(“EGC”),~~constitute aforward-looking ~~Delaware~~statements ~~corporation~~within ~~and~~the ~~indirect~~meaning ~~wholly-owned subsidiary~~ of ~~Energy~~the ~~XXI~~Private ~~Ltd,~~Securities anLitigation ~~exempted~~Reform ~~company~~Act ~~under the laws~~ of ~~Bermuda (“Energy XXI”)~~1995. WeOur ~~operate~~forward-looking asstatements anare ~~independent~~subject ~~oil~~to ~~and~~various ~~natural~~risks, ~~gas~~uncertainties ~~exploration~~ and ~~production~~assumptions, ~~company~~including ~~with~~those ~~current~~to ~~operations~~which ~~concentrated~~we inrefer under the ~~U.S.~~headings ~~Gulf~~“Cautionary ofStatement ~~Mexico~~Concerning ~~shelf~~Forward-Looking (Statements” and “~~GoM~~Risk ~~shelf~~Factors”) ~~focusing~~in onItems ~~state~~1 and ~~federal~~1A ~~waters~~of ~~offshore Louisiana,~~Part ~~which~~I weof ~~consider~~ our ~~core~~2015 ~~area~~Annual Report.

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, par value $0.001 per share, were converted, in the aggregate, into the right to receive merger consideration consisting of approximately 65% in cash and 35% in shares of common stock of Energy XXI, par value $0.005 per share. Overview

~~The Merger resulted in~~ EPL ~~becoming~~Oil an& ~~indirect~~Gas, ~~wholly-owned subsidiary of Energy XXI~~Inc. ~~Therefore~~(“we,” ~~in the preparation of~~ “our ~~financial statements~~,” ~~we have applied~~ “~~pushdown~~us,” ~~accounting, based on guidance from~~ “the ~~Securities~~Company” ~~and~~or ~~Exchange Commission (~~“~~SEC~~EPL”). ~~Pushdown~~was ~~accounting~~incorporated ~~refers~~as toa ~~the~~Delaware ~~use~~corporation ofon ~~the~~January ~~acquiring~~29, ~~entity’s~~1998 ~~basis~~and ofis ~~accounting in the preparation of the acquired entity’s financial statements. As~~ a ~~result,~~wholly-owned ~~our~~subsidiary ~~separate financial statements reflect the new basis~~ of ~~accounting recorded by~~ Energy XXI ~~upon~~Gulf ~~acquisition. As such~~Coast, ~~in accordance with U~~Inc.S. ~~GAAP~~(“EGC”), ~~due to our new basis of accounting, our financial statements include~~ a ~~black~~Delaware ~~line~~corporation ~~denoting~~and ~~that~~indirect ~~our~~wholly-owned ~~financial~~subsidiary ~~statements covering periods prior to the date~~ of ~~the~~Energy ~~Merger~~XXI ~~are~~Ltd, ~~not~~an ~~comparable~~exempted tocompany ~~our~~under ~~financial statements as of and subsequent to~~ the ~~date~~laws of ~~the~~Bermuda ~~Merger. References to the~~ (“~~Predecessor~~Energy ~~Company~~XXI”). ~~refer~~We tooperate ~~reporting~~as ~~dates~~an ofindependent ~~the~~oil ~~Company~~and ~~through~~natural ~~June~~gas 3,exploration ~~2014, reflecting results of operations~~ and ~~cash~~production ~~flows~~company ofwith ~~the~~current ~~Company~~operations ~~prior~~concentrated toin the ~~Merger~~U.S. onGulf ~~our~~of ~~historical~~Mexico ~~accounting~~shelf ~~basis; subsequent thereto, the Company is referred to as the~~ (“~~Successor~~GoM ~~Company,~~shelf”) ~~reflecting~~focusing ~~the~~on ~~impact~~state ~~of pushdown accounting~~ and ~~the~~federal ~~results~~waters offshore ofLouisiana, ~~operations~~which ~~and~~we ~~cash~~consider ~~flows~~our ofcore ~~the Company subsequent to the Merger~~area.

~~Energy~~On ~~XXI~~June ~~follows~~3, ~~the~~2014, ~~“full~~Energy ~~cost”~~XXI, ~~method~~EGC, ofClyde ~~accounting~~Merger ~~for~~Sub, ~~its oil and gas producing activities~~Inc., ~~while~~a wewholly-owned ~~had~~subsidiary ~~historically~~of ~~followed~~EGC ~~the~~ (“~~successful~~Merger ~~efforts~~Sub”), ~~method~~and ofEPL, ~~accounting.~~completed ~~Subsequent to~~ the ~~Merger,~~transactions wecontemplated ~~converted~~by ~~our accounting method from successful efforts to~~ the ~~full~~Agreement ~~cost~~and ~~method~~Plan of ~~accounting~~Merger, todated beas ~~consistent with Energy XXI’s method~~ of ~~accounting~~March ~~pursuant~~12, to2014 ~~SEC~~(as ~~guidance~~amended, ~~which requires a reporting entity that follows~~ the ~~full~~“Merger ~~cost~~Agreement”), ~~method~~by toand ~~apply~~among ~~that~~Energy ~~method~~XXI, toEGC, ~~all~~Merger ofSub, ~~its operations~~ and ~~to the operations of its subsidiaries. Under U.S. GAAP~~EPL, apursuant ~~change~~to inwhich ~~accounting~~Merger ~~method~~Sub iswas ~~generally required~~merged towith beand ~~applied~~into ~~retroactively~~EPL inwith ~~order~~EPL tocontinuing ~~provide~~as ~~comparable~~the ~~historical~~surviving ~~period~~corporation ~~information~~(the ~~to users of financial statements~~“Merger”). ~~However,~~Pursuant ~~due~~ to the ~~new~~Merger ~~basis~~Agreement, ofat ~~accounting~~the ~~established~~effective astime ~~a result~~ of the Merger ~~transaction and pushdown accounting~~, ~~our~~the ~~financial~~issued ~~statements~~and ~~are~~outstanding noshares ~~longer~~of ~~comparable~~EPL tocommon ~~those~~stock ofwere ~~prior~~converted, ~~periods~~in ~~and~~the weaggregate, ~~have~~into ~~applied~~ the merger ~~full~~consideration ~~cost~~consisting ~~method~~ of ~~accounting~~approximately on65% ain ~~prospective~~cash ~~basis~~and ~~from~~35% ~~the~~in ~~date~~shares of ~~the~~Energy ~~Merger~~XXI common stock.

~~Under~~As a result of the ~~full~~Merger, ~~cost~~the ~~method~~future strategy of ~~accounting,~~EPL ~~the~~is ~~costs~~determined by Energy XXI’s Board of ~~unsuccessful,~~Directors. asOur ~~well~~fiscal asyear ~~successful,~~2016 ~~exploration~~capital ~~and~~budget ~~development~~is ~~activities~~approximately ~~are~~$26 ~~capitalized~~million, asexcluding ~~properties~~potential capitalized general and ~~equipment~~administrative expenses. ~~This~~For ~~includes~~the ~~any~~three ~~internal~~months ~~costs~~ended ~~that~~September ~~are~~30, ~~directly~~2015, ~~related~~our tocapital ~~property~~expenditures ~~acquisition~~totaled approximately $3 million, ~~exploration~~of which approximately $2 million was spent on development of core properties and $1 million on other assets. The budgeted capital is allocated to development activities, ~~but~~which ~~does~~are ~~not~~geared ~~include~~toward ~~any~~the ~~costs~~improvement ~~related~~of toexisting production, ~~general~~the ~~corporate~~continued ~~overhead~~development orof ~~similar~~core ~~activities.~~fields, ~~Gain~~and orthe performance ~~loss~~of onnecessary ~~the~~plugging, ~~sale~~abandonment orand other decommissioning activities.

29At June 30, 2015, our total proved reserves were 57.2 MMBOE of which 67% were oil and 76% were classified as proved developed. 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. 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 October 30, 2015, we estimate that our total proved reserve equivalent volumes as of June 30, 2015 would have been approximately 23.3% smaller 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.

~~TABLE~~We OFproduce ~~CONTENTS~~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.

dispositionKnown ofTrends oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Uncertainties

~~Under~~Commodity ~~the~~Price ~~full~~Volatility. Prices ~~cost~~for ~~method,~~ oil and natural gas ~~properties~~historically ~~include~~have ~~costs~~been ~~that~~volatile and are ~~excluded~~expected ~~from~~to ~~costs~~continue ~~being~~to ~~depleted~~be ~~or amortized~~volatile. ~~Costs~~Oil ~~excluded~~prices ~~from~~declined ~~depletion~~significantly orduring ~~amortization~~fiscal ~~represent~~year ~~investments in unevaluated properties and include non-producing leasehold~~2015, ~~geological~~ and ~~geophysical~~our ~~costs~~ability ~~associated~~to ~~with~~maintain ~~leasehold~~current orproduction ~~drilling~~levels ~~interests~~could ~~and~~be ~~exploration~~impacted ~~drilling~~by ~~costs.~~continued Wedownward ~~exclude~~pressure ~~these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based~~ on ~~fair~~oil ~~value~~prices. ~~Costs~~The ~~are~~posted ~~transferred~~price toper ~~the~~barrel ~~full~~for ~~cost~~West ~~pool~~Texas asintermediate ~~the~~light ~~properties~~sweet ~~are~~crude ~~evaluated~~oil, or ~~over~~WTI, ~~the~~for ~~life of~~ the ~~reservoir.~~period from

As noted above, prior to the Merger, we used the successful efforts method of accounting for oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and complete exploratory wells with found proved reserves, and to drill and complete development wells were capitalized. Exploratory drilling costs were initially capitalized, but charged to expense if and when a well was determined not to have reserves in commercial quantities. Geological and geophysical costs were charged to expense as incurred. Leasehold acquisition costs were capitalized as unproved properties. If proved reserves were discovered on undeveloped leases, the related leasehold costs were transferred to proved properties and amortized using the units of production method. For individual unevaluated properties with capitalized costs below a threshold amount, we allocated capitalized costs to earnings generally over the primary lease terms. Properties that were subject to amortization and those with capitalized costs greater than the threshold amount were assessed for impairment periodically. Capitalized costs of producing oil and natural gas properties were depreciated and depleted by the units-of-production method. 24

WeTABLE ~~produce~~OF 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. CONTENTS

~~Overview~~October 1, 2014 to September 30, 2015 ranged from a high of $91.01 to a low of $38.24, a decrease of 58.0%, and ~~Outlook~~the NYMEX natural gas price per MMBtu for the period October 1, 2014 to September 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 30, 2015, the spot market price for WTI was $45.09. 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. If we experience sustained periods of low prices for oil and natural gas, it will likely 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.

AsDecreasing aService ~~result~~Costs. We ~~of pushdown accounting in connection with the Merger, the Predecessor Company’s operations are deemed to~~ have ~~ceased~~also onseen ~~June~~a 3,significant ~~2014~~ and ~~the~~continuing ~~Successor~~reduction ~~Company~~in ~~began~~rig ~~operations~~rates ~~as of that date. In the following discussion, the consolidated financial information for the three~~ and ~~nine~~drilling ~~months ending March 31~~costs, ~~2015~~which ~~(reflecting~~should ~~operations~~allow ofus ~~the Successor Company) is not comparable~~ to ~~that~~spend ~~for~~less ~~the~~capital ~~three~~drilling ~~and nine months ending March 31, 2014 (reflecting operations of the Predecessor Company). However, the comparability of certain components of~~ our ~~operating~~development ~~results~~wells ~~and~~than ~~key~~in ~~operating~~prior ~~performance measures was not significantly impacted by the Merger, specifically those related to production, average oil and natural gas selling prices, revenues and lease operating expenses~~periods. ~~Therefore, we believe that comparing the Successor Company’s results of operations and cash flows with those of the Predecessor Company is useful when analyzing certain measures of our performance.~~

AsCeiling Test Write-down. During the three months ended September 30, 2015, we recognized a ~~result~~ceiling test write-down of ~~the~~our ~~Merger,~~oil ~~the~~and ~~future~~natural ~~strategy~~gas properties of ~~EPL~~$308.1 ismillion. ~~determined~~The bywrite-downs ~~Energy~~did ~~XXI’s~~not ~~Board~~impact ofour ~~Directors~~cash flows from operating activities but did increase our net loss for the quarter and stockholders’ deficit. ~~Our~~Further ~~fiscal~~ceiling ~~year~~test ~~2015~~write-downs ~~capital~~may ~~budget~~be isrequired ~~approximately~~if ~~$250~~oil ~~million~~and natural gas prices remain low or decline further, ~~excluding~~unproved ~~potential~~property values decrease, estimated proved reserve volumes are revised downward or the net capitalized ~~general~~cost of proved oil and ~~administrative~~gas ~~expenses~~properties otherwise exceeds the present value of estimated future net cash flows. ~~For~~Based on an estimated average oil and natural gas price calculated as the ~~nine~~unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 months ~~ended~~ending ~~March~~December 31, 2015, ~~our~~(reflecting ~~capital~~an ~~expenditures~~estimated ~~totaled~~price ~~approximately~~for ~~$228~~December ~~million~~1, of2015 ~~which~~based ~~approximately~~on ~~$157~~current ~~million~~strip ~~was~~pricing), ~~spent~~we onpresently ~~development~~expect to incur further impairment of ~~core~~$225 ~~properties,~~million to $30325 million onin ~~exploration~~the second fiscal quarter of ~~core~~2016. ~~properties~~If ~~and~~the ~~$41~~current ~~million~~low oncommodity ~~other~~price ~~assets.~~environment ~~The~~or ~~budgeted~~downward ~~capital~~trend isin ~~allocated~~oil toprices ~~development~~continues ~~activities~~beyond this first fiscal quarter of 2016, ~~which~~we ~~are~~could ~~geared~~incur ~~toward~~further ~~the~~impairment ~~improvement~~to ofour ~~existing~~full ~~production, the~~cost ~~continued~~pool ~~development~~in offiscal ~~core~~2016 ~~fields,~~and beyond based on the average oil and natural gas price calculated as the ~~performance~~unweighted arithmetic average of ~~necessary~~the ~~plugging,~~first-day-of-the-month ~~abandonment~~price ~~and~~for ~~other~~each ~~decommissioning~~month ~~activities~~within the previous 12-month period under the SEC pricing methodology.

~~Our~~BOEM ~~revenue,~~Supplemental ~~profitability~~Financial Assurance and/or ~~future~~Bonding ~~growth~~Requirements. In ~~rate~~April ~~depend~~2015, ~~substantially~~we onreceived ~~factors~~letters ~~beyond~~from the BOEM stating that certain of our ~~control,~~subsidiaries ~~such~~no aslonger ~~oil~~qualify ~~and~~for ~~natural~~waiver ~~gas~~of ~~prices,~~certain ~~tropical~~supplemental ~~weather,~~bonding ~~economic~~requirements for potential offshore decommissioning, ~~political~~plugging and ~~regulatory~~abandonment ~~developments~~liabilities. ~~and~~The ~~availability~~letters ofnotified ~~other~~us ~~sources~~that certain of ~~energy~~our subsidiaries must provide approximately $566.5 ~~Prices~~million in supplemental financial assurance and/or bonding for their offshore oil and ~~natural~~ gas ~~historically~~leases, ~~have~~rights-of-way, ~~been~~and ~~extremely~~rights-of-use ~~volatile~~ and ~~are~~easements. ~~expected~~In toJune ~~continue~~2015, we reached agreements with the BOEM pursuant to bewhich ~~volatile~~we provided $54.7 ~~Oil~~million ~~prices~~of ~~declined~~supplemental ~~severely~~bonds ~~during~~issued to the ~~second~~BOEM, ~~quarter~~and ofthe ~~our~~BOEM ~~2015~~agreed ~~fiscal~~to ~~year,~~withdraw its orders with ~~continued~~regard ~~lower~~to ~~prices~~supplemental inbonding and postpone until November 15, 2015 the ~~third~~issuance ~~fiscal~~of ~~quarter~~further requirements of ~~2015~~us related to these supplemental bonding obligations. ~~The~~On ~~posted~~June ~~price~~30, ~~per~~2015, ~~barrel~~we ~~for~~sold ~~West~~the ~~Texas~~East ~~intermediate~~Bay ~~light~~field, ~~sweet~~and ~~crude~~as ~~oil~~a result, the $566.5 million of requested supplemental bonding was reduced by approximately $178 million. We currently maintain approximately $58.3 million in lease and/or ~~WTI,~~area ~~for~~bonds issued to the ~~period~~BOEM ~~from~~and ~~January~~approximately 1,$122.5 ~~2014~~ million in bonds issued to ~~March~~predecessor ~~31,~~third ~~2015~~party ~~ranged~~assignors ~~from~~including acertain ~~high~~state regulatory bodies of ~~$107.95~~certain wells and facilities on leases pursuant to a ~~low~~contractual commitment made by us to those third parties at the time of ~~$43~~assignment with respect to the eventual decommissioning of those wells and facilities.39 Thus, aour ~~decrease~~total ofsupplemental 59bonding is approximately $180.8% million, ~~and~~with ~~the~~an ~~NYMEX~~annual ~~natural~~premium ~~gas~~expense ~~price~~of $2.7 million.

30In an attempt to mitigate our potential additional supplemental financial assurance and/or bonding requirements resulting from any waiver disqualifications and any forthcoming requirement from the BOEM, we are undertaking, or have already undertaken, certain initiatives that we believe would factor into the amount of additional supplemental financial assurance and/or bonding required by the BOEM, including the performance of tasks: (i) ensuring that we have received credit from the BOEM for all of the plugging and abandonment work completed to date for offshore assets in the federal OCS in the Gulf of Mexico; (ii) assuring that we have received credit from the BOEM for recent asset divestitures and any consequential reductions in associated bonding requirements such as, for example, the June 2015 sale of our interest in the East Bay field, and (iii) confirming that our existing bonds with third parties are accurately reflected in comparison with the BOEM’s various bonding requests. However, with respect to our existing bonds with

~~TABLE OF CONTENTS~~25

~~per~~TABLE ~~MMBtu~~OF for the period January 1, 2014 to March 31, 2015 ranged from a high of $6.15 to a low of $2.50, a decrease of 59.3%. As of April 30, 2015, the spot market price for WTI was $59.63. During January 2015, we entered into Argus-LLS three-way collars on 7,000 barrels of our estimated oil production per day from February through December 2015. CONTENTS

~~The~~third ~~recent~~parties ~~declines~~that inare ~~oil~~outstanding ~~prices~~as ~~have adversely affected our financial position and results~~ of ~~operations~~September ~~and the quantities of oil and natural gas reserves that we can economically produce. During the three and nine months ended March 31~~30, 2015, we ~~recognized~~can ~~ceiling~~provide ~~test~~no ~~write-downs~~assurance of our oil and natural gas properties of $430.9 million and $1.1 billion, respectively. These write-downs did not impact our cash flows from operating activities but did increase our net loss and reduce stockholder’s equity. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that ~~we could incur further impairment to our full cost pool in fiscal 2015 and 2016 based on~~ the ~~average~~BOEM ~~oil~~will ~~and~~consider ~~natural~~them ~~gas~~when ~~price~~determining ~~calculated as~~ the ~~unweighted~~total ~~arithmetic~~value ~~average~~ of ~~the~~additional ~~first-day-of-the-month~~financial ~~price~~assurances ~~for each month within the previous 12-month period under SEC pricing methodology. Additionally, if the current low commodity price environment~~ and/or ~~downward~~bonding ~~trend~~we inmust ~~oil prices continues, there is also a possibility that our estimated proved oil and natural gas reserves will be reduced from such estimated reserves as of June 30, 2014~~provide.

InSince ~~addition,~~our inJune ~~April~~ 2015, weagreements ~~received~~with ~~letters from~~ the ~~Bureau of Ocean Energy Management (the “~~BOEM”), ~~stating that~~ we nohave ~~longer~~worked ~~qualify~~towards ~~for~~preparing ~~waiver~~a oflong-term ~~certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that we must provide supplemental~~ financial assurance ~~and/or~~plan ~~bonding for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements~~ that ~~require~~we ~~supplemental~~could ~~bonding.~~submit ~~The~~to ~~BOEM has indicated~~ the ~~amount~~BOEM offor ~~such required supplemental bonding totals approximately $566~~approval.5 ~~million, which amount is currently being negotiated by us.~~ We ~~are~~have ~~currently~~held ~~evaluating~~meetings ~~the~~with ~~impact of~~ the BOEM ~~letters~~in onfurtherance ~~our future consolidated financial position, results~~ of ~~operations and cash flow. We intend to continue to work with~~ the ~~BOEM~~plan’s ~~staff~~development ~~to resolve this matter~~and, ~~and~~while ~~we have already undertaken~~ a ~~number~~version of ~~initiatives to mitigate our potential liability resulting from~~ the ~~waiver~~long-term ~~disqualification~~financial ~~and~~assurance toplan ~~limit~~could ~~the~~be ~~amount~~submitted ofby ~~required~~November ~~supplemental~~15, ~~bonding~~2015, ~~by ensuring~~ we ~~have~~are ~~received~~currently ~~credit~~seeking ~~for~~a ~~all~~30-day ofextension ~~the plugging and abandonment work completed~~ to ~~date as well as counting our existing bonds with third parties and certain letters of credit against~~ the ~~BOEM~~November ~~bonding~~15, ~~request.~~2015 Ifdate wein ~~are~~order ~~unable~~ to ~~obtain~~augment the ~~additional~~final ~~required~~plan ~~bonds~~in orlight ~~assurances requested, the BOEM may require any~~ of ~~our~~new ~~operations~~information ~~on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations~~received.

IfIn October 2015, we ~~experience~~received ~~sustained~~information ~~periods~~from the BOEM indicating that, following November 15, 2015, we may receive additional demands of ~~low~~supplemental ~~prices~~financial assurance for ~~oil~~amounts ~~and~~in ~~natural~~addition ~~gas~~to the $566.5 million initially sought by the BOEM in April 2015, itprimarily ~~will~~relating ~~likely~~to ~~have~~certain properties that are no longer exempt from supplemental bonding as a ~~further~~result ~~material~~of ~~adverse~~co-owners ~~effect~~losing ontheir ~~our~~exemptions. We believe a substantial portion of the additional supplemental financial ~~position,~~assurance and/or bonding that may be sought by the BOEM may relate to circumstances that could eventually be removed from our ~~results~~responsibility (in terms of providing ~~operations~~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 ~~quantities~~permitted operator and no drilling of ~~oil~~wells has occurred. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and ~~natural~~address ~~gas~~these ~~reserves~~potential additional liabilities. We would expect that wemost, ~~can~~if ~~economically~~not ~~produce~~all, ~~and~~of our ~~access~~co-lessees towith ~~capital~~the remaining working interest in such lease interests will provide their share of the bonding.

WeConsequently, ~~intend~~as towe ~~continue~~currently toevaluate ~~focus~~the oninformation ~~integrating~~received ~~operations~~from tothe ~~realize~~BOEM ~~consolidation~~in ~~benefits~~October 2015 and ~~maximize~~after ~~returns~~taking oninto ~~existing~~account ~~assets~~items bythat ~~deploying~~we ~~capital~~expect ~~resources~~to onbe ~~lower~~able ~~risk~~to ~~development~~remove ~~drilling~~from inour ~~the~~responsibility ~~fields~~described ~~where~~above, we ~~have~~believe ~~previously~~that ~~enjoyed~~the ~~success,~~BOEM ~~and~~will ~~reducing~~assess ~~capital~~an ~~commitments~~additional on$125 ~~exploration~~to $200 million of supplemental financial assurance and/or bonding requirements on us in such other ~~activities~~letters that domay ~~not~~be ~~provide~~issued ~~incremental~~after ~~production~~November 15, ~~while~~2015 weif ~~seek~~these toitems ~~improve~~are ~~cash~~not ~~flow~~otherwise ~~and~~addressed ~~pay~~in ~~down~~our ~~debt.~~long-term Wefinancial ~~have~~assurance ~~also~~plan. ~~seen~~If awe ~~significant~~are ~~and~~successful ~~continuing~~in ~~reduction~~obtaining inthe ~~rig~~30-day ~~rates~~extension, ~~and~~we ~~drilling~~intend ~~costs,~~for ~~which~~our ~~should~~long-term ~~allow~~financial usassurance plan to ~~spend~~address ~~less~~these additional ~~capital~~financial ~~drilling~~assurance ~~our~~requirements ~~development~~for ~~wells~~which ~~than~~we received information in ~~prior~~October ~~periods~~2015. ~~Jack~~Please note if our co-uplessees ~~rig~~and ~~rates,~~us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for ~~example~~ such specified leases and present such agreed upon allocations to the BOEM for approval, ~~have~~the ~~fallen~~BOEM bymay ~~35 – 50%~~direct insupplemental ~~recent~~financial ~~months~~assurance and/or ~~other~~bonding ~~service~~amounts ~~providers~~for ~~are~~100% ~~similarly~~of ~~cutting~~the ~~their~~lease ~~rates~~interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements.

~~Known~~Unrelated ~~Trends~~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, ~~Uncertainties~~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.

~~Ceiling~~While ~~Test Write-down. During~~ the ~~three~~Draft ~~and~~Guidance, ~~nine~~once ~~months~~implemented ~~ended~~by ~~March~~the 31BOEM, ~~2015,~~would weallow ~~recognized~~an ~~write-downs~~increased number of ~~our~~operators ~~oil~~(relative to those operators under the existing NTL regarding supplemental financial assurance and ~~natural~~bonding) ~~gas~~to ~~properties.~~self-insure Iffor ~~the~~their ~~current~~decommissioning ~~low~~liabilities ~~commodity~~that ~~price~~is ~~environment~~no ormore ~~downward~~than ~~trend~~10% inof ~~oil~~their ~~prices~~tangible ~~continues~~net worth, there is ano ~~reasonable~~assurance ~~likelihood~~ that wethe ~~could~~BOEM ~~incur~~will ~~further~~allow ~~impairment~~us to ~~our~~utilize ~~full~~self-insurance ~~cost~~programs ~~pool~~and inwe ~~fiscal~~currently ~~2015~~do ~~and~~not ~~2016~~plan for self-insurance under the long-term financial assurance plan that we plan to submit to the BOEM.

Oil Spill Response Plan. Energy XXI maintains a Regional Oil Spill Response Plan (the “Plan”) that defines response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the Bureau of Safety and Environmental Enforcement (“BSEE”) bi-annually, except when changes are required, in which case revised plans are required to be submitted for 26

31TABLE OF CONTENTS

~~TABLE~~In OFaddition ~~CONTENTS~~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 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 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 terminated, and such action could have a material 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 “Plan”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the Bureau of Safety and Environmental Enforcement (“BSEE”) bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BSEE. Additionally, these plans are tested and drills are conducted periodically at all levels of the Company.

~~Hurricanes. Since~~We ~~the~~have ~~majority~~contracted ofwith ~~our~~an ~~production~~emergency ~~originates~~and spill response management consultant, to provide management expertise, personnel and equipment, under our supervision, in the ~~Gulf~~event of ~~Mexico~~an incident requiring a coordinated response. Additionally, we are ~~particularly~~a ~~vulnerable~~member toof ~~the~~Clean ~~effects~~Gulf Associates (“CGA”), a not-for-profit association of ~~hurricanes~~producing onand ~~production.~~pipeline ~~Significant~~companies ~~hurricane~~operating ~~impacts~~in ~~could~~the ~~include~~Gulf ~~reductions~~of Mexico and~~/or~~ ~~deferrals~~has ofcapabilities ~~future~~to ~~oil~~simultaneously ~~and~~respond ~~natural~~to ~~gas~~multiple ~~production~~spills. ~~and~~CGA ~~revenues~~has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), ~~increased~~a ~~lease~~private, ~~operating~~not-for-profit ~~expenses~~marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit ~~evacuations~~organization ~~and~~created ~~repairs~~to assist the petroleum and ~~possible~~energy-related ~~acceleration~~industries by addressing problems caused by oil spills on water. In the event of ~~plugging~~a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and ~~abandonment~~dispersant ~~costs~~capabilities for CGA member companies.

~~RESULTS~~Hurricanes. Since OFthe ~~OPERATIONS~~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.

~~The following table presents information about our oil and natural gas operations (in thousands, except per unit amounts).~~ 27

	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014			Nine Months Ended March 31, 2015			Nine Months Ended March 31, 2014
Net production (per day):
Oil (Bbls)		17,437			16,250			17,992			16,280
Natural gas (Mcf)		48,907			27,507			42,077			30,120
Total (Boe)		25,588			20,835			25,005			21,300
Average sales prices(1):
Oil (per Bbl)	$	47.40		$	99.56		$	76.47		$	100.57
Natural gas (per Mcf)		2.92			5.20			3.47			4.19
Total (per Boe)		37.89			84.51			60.87			82.80
Oil and natural gas revenues (in thousands):
Oil	$	74,392		$	145,605		$	377,012		$	448,635
Natural gas		12,861			12,865			40,031			34,594
Total		87,253			158,470			417,043			483,229
Impact of derivatives instruments settled during the period(1):
Oil (per Bbl)				$	(11.27	)				$	(5.31	)
Natural gas (per Mcf)					(0.17	)					(0.05	)
Average costs (per Boe):
LOE	$	21.53		$	22.26		$	23.52		$	21.11
Taxes, other than on earnings		1.33			1.32			1.10			1.43
General and administrative (“G&A”) expenses		5.21			5.49			3.92			4.10
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil	$	(76,276	)				$	(107,490	)
Changes in production volumes of oil		5,063						35,867
Total decrease in oil sales		(71,213	)					(71,623	)
Changes in prices of natural gas	$	(1,100	)				$	(5,954	)
Changes in production volumes of natural gas		1,096						11,391
Total increase (decrease) in natural gas sales		(4	)					5,437

TABLE OF CONTENTS

(1)Results For the three and nine months ended March 31, 2015, our oil and natural gas revenues and resulting average sales prices include the impact of accounting for our derivative financial instruments as cash flow hedges.Operations

32Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

~~TABLE~~Our OFconsolidated ~~CONTENTS~~net loss for the three months ended September 30, 2015 was $334.6 million as compared to $306.4 million for the three months ended September 30, 2014. The increase in the net loss was primarily due to lower revenues due to lower oil and natural gas sales prices, partially offset by lower lease operating expenses.

ThreeRevenue Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014Variances

Overview


	Three Months Ended September 30,				Increase (Decrease)			Percent Increase (Decrease)
	2015		2014		Increase (Decrease)			Percent Increase (Decrease)
			(In thousands)
Oil	$	73,372	$	158,316	$	(84,944	)		(53.7	)%
Natural gas		12,618		13,954		(1,336	)		(9.6	)%
Gain on derivative financial instruments		2,778		21,857		(19,079	)		(87.3	)%
Total Revenues	$	88,768	$	194,127	$	(105,359	)		(54.3	)%

Our ~~operating~~consolidated ~~results~~revenues ~~for~~decreased $105.4 million in the ~~three~~first ~~months~~quarter ~~ended~~of ~~March~~fiscal ~~31,~~2016 ~~2015,~~as compared to the ~~three~~same ~~months~~period ~~ended~~in ~~March~~the ~~31,~~prior ~~2014,~~fiscal ~~reflect~~year. aLower 7%revenues ~~increase~~were inprimarily ~~oil~~due ~~production~~to ~~and~~lower acommodity ~~78%~~sales ~~increase~~prices inand ~~natural~~lower ~~gas~~gain ~~production.~~on ~~Our~~derivative ~~product~~financial ~~mix~~instruments. ~~for~~Revenue ~~the~~variances ~~three~~related ~~months~~to ~~ended~~commodity ~~March 31~~prices, ~~2015~~sales ~~was~~volumes ~~68%~~and ~~oil~~hedging ~~(including~~activities ~~natural~~are ~~gas~~presented ~~liquids)~~in ~~compared to 78% for~~ the ~~three~~following ~~months~~table ~~ended~~and ~~March~~described ~~31, 2014~~below.

RevenuePrice and Volume Variances

	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014			$ Change			% Change
	Three Months Ended September 30,						Increase (Decrease)			Percent Increase (Decrease)			Revenue Increase (Decrease)
	(in thousands)			(in thousands)
	2015			2014
Oil and natural gas revenues	$	87,253		$	158,470		$	(71,217	)		-45	%
													(In thousands)
Price Variance
Oil sales prices (per Bbl)	$	44.74		$	95.26		$	(50.52	)		(53.0	)%	$	(83,960	)
Natural gas sales prices (per Mcf)		2.65			3.92			(1.27	)		(32.4	)%		(4,520	)
Gain on derivative financial instruments (per BOE)		1.14			9.69			(8.55	)		(88.2	)%		(19,079	)
Total price variance														(107,559	)
Volume Variance
Oil sales volumes (MBbls)		1,640			1,662			(22	)		(1.3	)%		(984	)
Natural gas sales volumes (MMcf)		4,767			3,564			1,203			33.8	%		3,184
BOE sales volumes (MBOE)		2,435			2,256			179			7.9	%
Percent of BOE from oil		67	%		74	%
Total volume variance														2,200
Total price and volume variance													$	(105,359	)

ForPrice the three months ended March 31, 2015, our oil and natural gas revenues decreased 45% as compared to the three months ended March 31, 2014, due primarily to a 52% decrease in average selling prices for our oil, partially offset by a 7% increase in oil production. Natural gas revenues were essentially flat with a 78% increase in natural gas production offset by a 44% decrease in average selling prices in the three months ended March 31, 2015, as compared to the three months ended March 31, 2014. Revenues for the three months ended March 31, 2015 include $1.8 million from the impact of hedge accounting. Variances

~~Our~~Commodity ~~overall average selling~~ prices ~~decreased~~are byone ~~55%~~of ~~for~~ the ~~three~~key ~~months~~drivers ~~ended~~of ~~March~~our ~~31,~~earnings ~~2015~~and ~~when~~net ~~compared~~operating tocash ~~the~~flow. ~~three~~Lower ~~months~~commodity ~~ended~~prices ~~March~~decreased ~~31,~~revenues ~~2014~~by $107.6 ~~Commodity~~million ~~prices~~in ~~are one of~~ the ~~key~~first ~~drivers~~quarter of ~~earnings~~fiscal ~~generation~~2016 ~~and~~as ~~net~~compared ~~operating~~to ~~cash~~the ~~flow.~~same ~~Average~~period ~~crude~~in ~~oil~~the ~~prices,~~prior ~~including~~fiscal ~~a $0~~year.75 ~~realized~~Average ~~gain~~oil ~~per~~prices ~~barrel related to hedging activities,~~ decreased $5250.1652 per barrel in the ~~third~~first quarter of fiscal ~~2015~~2016, resulting in lower revenues of ~~approximately~~ $7684.30 million. Average natural gas prices, ~~including~~decreased a $01.1527 ~~realized gain~~ per Mcf ~~related~~in tothe ~~hedging~~first ~~activities,~~quarter ~~decreased~~of ~~$2.28~~fiscal ~~per~~2016 ~~Mcf~~compared into the ~~third~~first quarter of fiscal 2015, resulting in lower revenues of ~~approximately~~ $14.15 million. ~~Commodity~~For ~~prices~~the ~~are~~first ~~affected~~quarter byof ~~many~~fiscal ~~factors~~2016, ~~that are outside of~~ our ~~control~~hedging ~~and~~activities weresulted ~~cannot~~in ~~accurately~~a ~~predict~~gain ~~future~~on derivative ~~commodity~~activities ~~prices~~of $1.14 ~~Depressed~~per ~~commodity~~BOE ~~prices~~compared ~~over~~to ana ~~extended~~gain ~~period~~ of ~~time~~$9.69 ~~could~~per ~~result~~BOE infor ~~reduced~~the ~~cash~~same ~~flow~~period ~~from operating activities, potentially causing us to reduce spending on our capital program. Reductions~~ in ~~our~~the ~~capital~~prior ~~expenditures~~fiscal ~~could~~year, ~~result~~resulting in alower ~~reduction~~revenues of ~~production~~$19.1 ~~volumes~~million.

~~Operating Expenses~~28

~~Our~~TABLE ~~operating~~OF ~~expenses primarily consist of the following:~~ CONTENTS

	Three Months Ended March 31, 2015			Three Months Ended March 31, 2014			$ Change		% Change
	(in thousands)			(in thousands)
LOE	$	49,571		$	41,734		$	7,837		19	%
Exploration expenditures and dry hole costs(1)		—			4,941			NM		NM
Impairment of oil and natural gas properties		430,859			61			NM		NM
DD&A, including accretion expense(1)		79,085			52,642			NM		NM
G&A expenses		11,998			10,287			1,711		17	%
Taxes, other than on earnings		3,057			2,472			585		24	%
Other		(3	)		(942	)		939		-100	%

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 could result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. Reductions in our capital expenditures could result in a reduction of production volumes.

NM — NotVolume meaningful. Variances

~~(1)~~Sales ~~Exploration~~volumes ~~expenditures~~are ~~and~~another ~~dry~~key ~~hole~~driver ~~costs,~~of our earnings and ~~DD&A~~net operating cash flow. Oil sales volumes decreased 0.2 MBbls per day in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, ~~including~~resulting ~~accretion~~in ~~expense~~lower revenues of $1.0 million. Natural gas sales volumes were higher in the first quarter of fiscal 2016, ~~are~~increasing ~~not~~13.1 ~~comparable~~MMcf per day for the ~~periods~~first ~~presented~~quarter ~~due~~of fiscal 2016 as compared to the ~~conversion~~same ~~from~~period ~~successful~~in ~~efforts~~the ~~accounting~~prior tofiscal ~~full~~year, ~~cost~~resulting ~~accounting~~in ~~effective~~higher ~~June~~revenues 4,of ~~2014~~$3.2 million.

33Costs and Expenses and Other (Income) Expense

TABLE OF CONTENTS


	Three Months Ended September 30,										Increase (Decrease) Total $
	2015						2014
	Total $			Per BOE			Total $		Per BOE
	(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense	$	26,153		$	10.74		$	56,300	$	24.96	$	(30,147	)
Transportation		723			0.30			625		0.28		98
Depreciation, depletion and amortization		57,660			23.68			73,745		32.69		(16,085	)
Accretion of asset retirement obligations		6,741			2.77			6,181		2.74		560
Impairment of oil and natural gas properties		308,078			126.52			—		—		308,078
Goodwill impairment		—			—			329,293		145.96		(329,293	)
General and administrative		7,944			3.26			8,042		3.56		(98	)
Taxes, other than on earnings		(935	)		(0.38	)		2,528		1.12		(3,463	)
Other		—			—			21		0.01		(21	)
Total costs and expenses	$	406,364		$	166.88		$	476,735	$	211.32	$	(70,371	)
Other (income) expense
Interest income	$	(12	)	$	—		$	—	$	—	$	(12	)
Interest expense		16,984			6.97			10,901		4.83		6,083
Total other expense	$	16,972		$	6.97		$	10,901	$	4.83	$	6,071

~~LOE~~Costs ~~increased~~and ~~for~~expenses ~~the~~decreased ~~three~~$70.4 ~~months~~million ~~ended~~in ~~March~~the ~~31,~~first ~~2015,~~quarter of fiscal 2016 as compared to the ~~three~~same ~~months~~period ~~ended~~in ~~March~~the ~~31,~~prior ~~2014~~fiscal year, ~~primarily~~principally due to the ~~acquisition~~decrease ofin ~~the~~lease EIoperating ~~Interests~~expense and SPdepreciation, 49depletion ~~Interests~~and amortization (“DD&A”) 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 test at ~~March~~September 3130, 2015, we recognized a ceiling test impairment of our oil and natural gas properties totaling $~~430~~308.91 million during the quarter ended September 30, 2015.

~~Under successful efforts accounting during the three months ended March 31, 2014, we recorded approximately $2.0 million in seismic expense and $2.9 million of other exploratory expenses.~~ 29

~~G&A~~TABLE ~~expenses~~OF increased for the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, primarily due to the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate, Energy XXI Services, LLC (“Energy Services”), which we entered into in connection with the Merger. CONTENTS

~~For~~During the ~~three~~quarter ~~months~~ ended ~~March~~September 3130, 2014, ~~other~~we ~~operating~~recorded ~~expenses~~a ~~included~~non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero as of September 30, 2014. At September 30, 2014, we performed a ~~gain~~goodwill onimpairment ~~abandonment~~test ~~activities~~after assessing relevant events and circumstances, primarily the decline in oil prices since June 30, 2014. In the first step of $0the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital, both of which adversely impacted the fair value of our estimated reserves.9 ~~million~~Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at September 30, 2014.

~~Other~~Lease ~~Income~~operating expense decreased $30.1 million in the first 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, downward revision in estimates and ~~Expense~~decrease in demand for oil field services. Lease operating expense per BOE declined from $24.96 for the quarter ended September 30, 2014 to $10.74 for the quarter ended September 30, 2015.

~~Interest~~DD&A expense decreased ~~approximately~~ $016.71 million ~~for~~in the ~~three~~first ~~months~~quarter ~~ended~~of ~~March~~fiscal ~~31,~~2016 ~~2015,~~ as compared to the ~~three~~same ~~months~~period ~~ended~~in ~~March~~the ~~31,~~prior ~~2014~~fiscal ~~due~~year, primarily due to a decrease in ~~our~~the ~~effective~~DD&A ~~interest~~per BOE rate onof ~~the 8~~$9.~~25%~~01, ~~Senior~~which ~~Notes~~decreased ~~from~~DD&A ~~9.1%~~expense toby 5$20.~~8%,~~3 ~~reflecting~~million. ~~the~~This ~~impact~~decrease ofwas ~~the~~partially ~~fair~~offset ~~value~~by ~~adjustment~~an toincrease ~~the~~in ~~carrying~~DD&A ~~amount~~expense of ~~the 8~~$4.~~25%~~2 ~~Senior~~million ~~Notes~~due ~~recorded~~to inhigher ~~pushdown~~net ~~accounting~~production. ~~This~~The decrease ~~was~~in ~~partially~~the ~~offset~~DD&A byrate ~~an increase~~ in ~~interest~~the ~~expense~~first onquarter ~~our~~of ~~revolver~~fiscal ~~debt,~~2016 was primarily due to the ~~increase~~reduction in ~~revolver~~our ~~debt~~full ~~associated~~cost ~~with~~pool due to the ~~purchase~~impairments of our oil and natural gas properties in prior quarterly periods of fiscal year 2015 resulting from the ~~SP49~~ceiling test, ~~Interests~~partially offset by the reduction in proved reserve estimates.

~~Other~~Interest ~~income (~~expense) inincreased ~~the~~approximately ~~three months ended March 31, 2014 includes a net loss on derivative instruments of~~ $136.1 million ~~consisting~~in ~~of a gain of $3.7 million due to~~ the ~~change~~first inquarter ~~fair value~~ of ~~derivative~~fiscal ~~instruments~~2016 ~~which~~as ~~were~~compared to bethe ~~settled~~same period in the ~~future~~prior ~~offset~~fiscal ~~by a loss of $16.9 million on derivative instruments settled during the quarter~~year, primarily ~~from~~due ~~the~~to ~~impact~~interest ofon ~~higher oil prices during 2014. Prior to~~ the ~~Merger,~~promissory wenote ~~did~~payable ~~not elect~~ to ~~designate derivative instruments as hedges~~EGC.

Income Taxes

The income tax ~~benefit~~expense for the ~~three~~first ~~months~~quarter ~~ended~~of ~~March~~fiscal ~~31,~~2016 ~~2015~~ is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. ~~This~~We ~~effective~~recorded ~~rate~~no ~~excludes~~income tax expense (benefit) in the ~~effect~~first quarter of ~~the~~fiscal ~~goodwill~~2016 ~~impairment~~compared ~~charge~~to ~~recorded~~income tax expense of $12.8 million in the first quarter of fiscal 2015. For first quarter of fiscal 2015, our effective income tax rate was 35.9%, which excludes the impact of the goodwill impairment charge recorded during the period, which is not deductible for income tax purposes and was treated as a discrete item for purposes of computing our interim provision ~~(benefit)~~ for income taxes. The ~~effective~~decrease ~~income~~in the tax~~/(benefit)~~ rate ~~for~~is ~~the~~primarily ~~three~~due ~~months~~to ~~ended~~the ~~March~~book ~~31,~~loss ~~2015~~for ~~was~~the ~~(38.0)%~~quarter, asthe ~~compared~~forecast tobook ~~36.4%~~loss for the ~~three~~year ~~months~~and ~~ended~~our ~~March~~inability ~~31,~~to ~~2014.~~currently ~~The~~record ~~increase~~any inadditional ~~the~~net deferred tax ~~rate~~assets isdue ~~primarily~~to ~~due~~a preponderance of negative evidence as to anfuture ~~increase~~realizability inof ~~common~~these ~~permanent difference~~deferred ~~items~~tax assets. See Note ~~10, “~~8 — Income Taxes” in ~~the~~Notes ~~condensed~~to ~~consolidating~~Consolidated ~~financial~~Financial ~~statements~~Statements in ~~Part 1, Item 1 of~~ this Quarterly Report.

34Liquidity and Capital Resources

TABLE OF CONTENTSOverview

~~Nine~~Currently, ~~Months~~we ~~Ended~~fund ~~March~~our 31operations primarily through cash flows from operating activities and advances from EGC. Future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. Oil prices declined severely during the second quarter of our fiscal year 2015, ~~Compared~~with tocontinued ~~Nine~~lower ~~Months~~prices ~~Ended~~throughout ~~March~~the 31second half of fiscal year 2015 and the first quarter of fiscal 2016. These lower commodity prices have negatively impacted revenues, ~~2014~~earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.

~~Overview~~As of September 30, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are party with EGC, and we were in compliance with all covenants thereunder. As part of our quarterly compliance certificates required under our revolving credit agreement and also as a condition to borrow funds or issue letters of credit under our revolving credit agreement, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our revolving credit facility, as amended to date. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future

Our operating results for the nine months ended March 31, 2015, compared to the nine months ended March 31, 2014, reflect an 11% increase in oil production and a 40% increase in natural gas production. Our product mix for the nine months ended March 31, 2015 was 72% oil (including natural gas liquids) compared to 76% for the nine months ended March 31, 2014. 30

~~Revenue~~TABLE OF CONTENTS

	Nine Months Ended March 31, 2015		Nine Months Ended March 31, 2014		$ Change			% Change
	(in thousands)		(in thousands)
Oil and natural gas revenues	$	417,043	$	483,229	$	(66,186	)		-14	%

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. In addition, based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods, including periods prior to June 30, 2016. We continue to focus on reducing our leverage and are working with our bank group on certain amendments to our First Lien Credit Agreement to address these concerns. There can be no assurance any of these discussions or transactions will prove successful. 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 could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

~~For~~Borrowings ~~the~~under ~~nine~~our ~~months~~First ~~ended~~Lien ~~March~~Credit ~~31,~~Agreement ~~2015,~~are ~~our~~limited to a borrowing base based on oil and natural gas ~~revenues~~reserve ~~decreased~~values ~~14%~~which asare ~~compared~~re-determined toon a periodic basis. We and our lenders are currently in the ~~nine~~process ~~months~~of ~~ended~~our ~~March~~fall ~~31,~~borrowing ~~2014~~base redetermination, ~~due~~which ~~primarily~~we expect to anconclude ~~11%~~during ~~increase~~December in2015. ~~oil~~Given ~~production~~EGC’s ~~partially~~current ~~offset~~borrowing bybase aat ~~24%~~$500 ~~decrease~~million inand ~~average~~the ~~selling~~resulting ~~prices~~asset coverage for ~~our~~the ~~oil.~~Revolving ~~Additionally~~Credit Facility, we ~~had~~do anot ~~40%~~currently ~~increase~~anticipate any borrowing base reductions in ~~natural~~connection ~~gas~~with ~~production~~the ~~and~~current ~~partially~~borrowing ~~offset~~base byredetermination. aHowever, ~~17%~~it ~~decrease~~is inpossible ~~average~~if ~~selling~~commodity prices ~~for~~were ~~natural~~to ~~gas~~decline insignificantly from ~~the~~current ~~nine~~levels, ~~months~~our ~~ended~~borrowing ~~March~~base ~~31,~~under ~~2015,~~our asRevolving ~~compared~~Credit toFacility ~~the~~may ~~nine~~be ~~months~~reduced ~~ended~~in ~~March~~subsequent 31redeterminations, ~~2014.~~which ~~Revenues~~would ~~for~~impact the ~~nine~~working ~~months~~capital ~~ended~~available ~~March~~to ~~31,~~fund ~~2015~~our ~~include~~capital ~~$26~~spending program.9 ~~million~~In ~~from~~addition, ~~the~~we ~~impact~~would have to repay any outstanding indebtedness in excess of ~~hedge~~any ~~accounting~~reduced borrowing base.

As of September 30, 2015, we had total indebtedness of $1,012.7 million as described in greater detail under — Our ~~overall~~Indebtedness ~~average~~and ~~selling~~Available ~~prices~~Credit. ~~decreased~~During byOctober ~~26%~~2015, ~~for~~we repurchased $29.8 million in aggregate principal amount of the ~~nine~~8.25% ~~months~~Notes ~~ended~~due ~~March~~2018 in open market transactions at a total price of approximately $10.0 million. As a result, we had total indebtedness of $981.4 million net of approximately $1.5 million in debt premium as of October 31, 2015. ~~when~~All ~~compared~~of our outstanding indebtedness will mature within the next three years. In addition, the maturity of certain of our and EGC’s outstanding indebtedness may be accelerated in certain situations. Pursuant to the ~~nine~~indenture ~~months~~governing ~~ended~~EGC’s ~~March~~11.0% 31Notes, ~~2014~~EGC will be required to offer to purchase all outstanding 11.0% ~~Average~~Notes ~~crude~~if ~~oil~~a ~~prices~~“triggering event” occurs, ~~including~~at a $5price of 100% of the principal amount of the 11.190% ~~realized~~Notes ~~gain~~purchased ~~per~~plus ~~barrel~~accrued ~~related~~and unpaid interest to ~~hedging~~the ~~activities,~~date ~~decreased~~of ~~$24~~purchase.10 ~~per~~For ~~barrel~~this inpurpose, a “triggering event” will be deemed to occur (i) on the ~~first~~30th ~~nine~~day ~~months~~prior to the stated maturity date of ~~fiscal~~the ~~2015~~9.25% Senior Notes (December 15, ~~resulting~~2017), inif ~~lower~~on ~~revenues~~such date the aggregate outstanding principal amount of ~~approximately~~all such notes exceeds $~~107~~250.50 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% ~~Average~~Senior ~~natural~~Notes ~~gas~~(February ~~prices~~15, ~~including~~2018), aif on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million.12 ~~realized~~In ~~gain~~addition, ~~per~~our ~~Mcf~~revolving ~~related~~credit facility is scheduled to ~~hedging~~mature ~~activities~~on April 9, ~~decreased~~2018; ~~$0.72~~however, ~~per~~the ~~Mcf~~maturity inof our revolving credit facility will accelerate if the ~~first~~9.25% ~~nine~~Senior ~~months~~Notes ofare ~~fiscal~~not ~~2015,~~retired ~~resulting~~or inrefinanced ~~lower~~by ~~revenues~~May of15, ~~approximately~~2017 $6or the 8.025% ~~million~~Senior Notes are not retired or refinanced by July 15, 2017.

~~Operating~~Our ~~Expenses~~ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our ability to maintain and grow reserves and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. For example, constraints in the credit markets may increase the rates we are charged for utilizing these markets. 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 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

~~Our operating expenses primarily consist of the following:~~ 31

	Nine Months Ended March 31, 2015		Nine Months Ended March 31, 2014		$ Change			% Change
	(in thousands)		(in thousands)
LOE	$	161,175	$	123,203	$	37,972			31	%
Exploration expenditures and dry hole costs(1)		—		23,033		NM			NM
Impairment of oil and natural gas properties		1,113,727		827		NM			NM
Goodwill impairment		329,293		—		NM			NM
DD&A, including accretion expense(1)		253,656		169,244		NM			NM
G&A expenses		26,850		23,923		2,927			12	%
Taxes, other than on earnings		7,529		8,363		(834	)		-10	%
Other		18		27,457		(27,439	)		-100	%

TABLE OF CONTENTS

~~NM — Not~~satisfy ~~meaningful~~our obligations under our indebtedness, which may not be successful” in our 2015 Annual Report. Based on our current production levels and prices for oil and natural gas, our liquidity and capital resource alternatives may not be sufficient to meet our funding requirements through September 30, 2016, without additional advances from EGC, further reductions in capital expenditures or sales of non-core assets by us or EGC. EGC and its parent intend to support us financially to enable us to meet our ongoing obligations and comply with our covenants.

~~(1)~~In ~~Exploration~~light ~~expenditures~~of current commodity prices and ~~dry~~our ~~hole~~substantial ~~costs~~leverage position, EGC’s parent continues to analyze a variety of transactions and ~~DD&A~~mechanisms designed to reduce debt, including ~~accretion~~the ~~expense~~retirement or purchase of outstanding debt securities, ~~are~~including ~~not~~our ~~comparable~~outstanding debt securities, through cash purchases in open market purchases and/or exchanges for ~~the~~equity ~~periods~~or ~~presented~~other ~~due~~securities toof the ~~conversion~~Company ~~from~~through ~~successful~~privately ~~efforts~~negotiated ~~accounting~~transactions toor ~~full~~otherwise ~~cost~~and ~~accounting~~opportunistic ~~effective~~acquisitions. ~~June~~Such 4transactions, ~~2014~~if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors and there can be no assurance that we will take any of these actions.

LOEOur increasedIndebtedness for the nine months ended March 31, 2015, as compared to the nine months ended March 31, 2014, primarily due to the acquisition of the EI Interests and SPAvailable 49 Interests. LOE for the nine months ended March 31, 2015 also included non-routine costs associated with pipeline maintenance in two fields in addition to other non-routine workover and other expenses. Credit

35Revolving Credit Sub-Facility. The First Lien Credit Agreement, as amended, has a maximum facility amount and borrowing base for EGC of $500 million, of which such amount $150 million is the borrowing base for EPL (the “Revolving Credit Sub-Facility”). As of September 30, 2015, we have fully utilized amounts available under our Revolving Credit 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 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. Our 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.

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

~~During~~Since ~~the~~required ~~nine~~lender ~~months~~consent ~~ended~~to ~~March~~the ~~31,~~specific ~~2015,~~terms weof ~~recorded~~the atransaction ~~non-cash~~with ~~impairment~~respect ~~charge~~to the sale of ~~$329.3~~the ~~million~~East toBay ~~reduce~~field ~~the~~had ~~carrying~~not ~~value~~been ofobtained, ~~goodwill~~EGC toand ~~zero~~EPL aswere ofin ~~September~~technical default under the First Lien Credit Agreement at June 30, ~~2014~~2015. AtOn ~~September~~July 3014, ~~2014~~2015, we ~~performed~~obtained a ~~goodwill~~waiver ~~impairment~~to ~~test~~this ~~after~~event ~~assessing~~of ~~relevant~~default, ~~events~~which ~~and~~waiver ~~circumstances,~~required ~~primarily~~EPL ~~the~~to ~~decline~~deposit in$21 ~~oil~~million ~~prices~~into ~~since~~an ~~June~~account ~~30,~~subject ~~2014.~~to Ina ~~the~~control ~~first~~agreement ~~step~~in favor of the ~~goodwill~~administrative ~~impairment~~agent ~~test,~~under wethe ~~determined~~First ~~that~~Lien ~~the~~Credit ~~fair~~Agreement. ~~value~~Such ofamount ~~our~~will ~~reporting~~remain ~~unit~~on ~~was~~deposit ~~less~~until ~~than~~ the ~~carrying~~next ~~amount,~~redetermination ~~including~~of ~~goodwill~~the borrowing base, ~~primarily~~unless ~~due~~used to ~~price~~repay ~~deterioration~~a inborrowing ~~forward~~base ~~pricing~~deficiency. ~~curves~~Upon ~~and~~the annext redetermination, ~~increase~~any inamounts ~~our~~remaining ~~weighted~~in ~~average~~the ~~cost~~account ofwill ~~capital~~ be used to ~~estimate~~make ~~fair~~an ~~value,~~immediate ~~both~~payment oftoward ~~which~~any ~~adversely~~borrowing ~~impacted~~base ~~the~~deficiency ~~fair~~at ~~value~~the time of ~~our~~such ~~reserves. Therefore~~redetermination, weand ~~performed~~so ~~the~~long ~~second~~as ~~step~~no event of ~~the~~default ~~goodwill~~shall ~~impairment~~have ~~test~~occurred, ~~which~~any ~~led~~amount usremaining toafter ~~conclude~~payment ~~that~~in ~~there~~full ~~would~~of beany noborrowing ~~remaining~~base ~~implied~~deficiency ~~fair~~shall ~~value~~be ~~attributable~~released toand ~~goodwill~~paid atto ~~September 30, 2014~~EGC.

As8.25% aSenior ~~result~~Notes. The 8.25% Senior Notes consist of ~~our~~$510.0 ~~ceiling~~million ~~tests~~in ataggregate ~~December~~principal ~~31,~~amount ~~2014~~issued ~~and~~under ~~March~~an ~~31,~~indenture ~~2015~~dated February 14, we2011 ~~recognized~~(the a“2011 ~~ceiling~~Indenture”). ~~test~~The ~~impairment~~8.25% Senior Notes bear interest from the date of ~~our~~their ~~oil~~issuance ~~and~~at ~~natural~~an ~~gas~~annual ~~properties~~rate ~~totaling~~of $18.125% ~~billion~~with ~~during~~interest ~~the~~due ~~nine~~semi-annually, ~~months~~in ~~ended~~arrears, ~~March~~on ~~31,~~February ~~2015~~15th and August 15th of each year. The 8.25% Senior Notes are fully and unconditionally

Under successful efforts accounting during the nine months ended March 31, 2014, we recorded approximately $13.1 million in seismic expense and $7.6 million of other exploratory expenses. We also recorded approximately $1.8 million of dry hole costs associated with an exploratory drilling operation which was unsuccessful. 32

~~G&A~~TABLE ~~expenses~~OF increased for the nine months ended March 31, 2015, as compared to the three months ended March 31, 2014, primarily due to the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate, Energy Services, which we entered into in connection with the Merger. CONTENTS

~~For~~guaranteed, ~~the~~jointly ~~nine~~and ~~months ended March 31~~severally, ~~2014,~~on ~~other~~an ~~operating~~unsecured ~~expenses~~senior ~~included~~basis ainitially ~~loss~~by oneach ~~abandonment activities~~ of ~~$21.0~~our ~~million~~existing direct and ~~amortization~~indirect ~~expense~~domestic ~~related~~subsidiaries to(other ~~our~~than ~~weather~~immaterial ~~derivative~~subsidiaries). ofThe $68.625% ~~million.~~Senior ~~For~~Notes ~~the~~will ~~nine~~mature ~~months~~on ~~ended~~February ~~March 31~~15, ~~2014,~~2018. ~~our~~As ~~loss on abandonment activities primarily reflected an increase~~ of ~~$21.8~~September ~~million~~30, in2015, ~~our~~we ~~ARO liability related to our only remaining four non-producing wellbores in our non-operated deepwater properties. These increased abandonment costs~~ were ~~primarily attributable to changes~~ in ~~regulatory~~compliance ~~interpretations~~with ~~and~~all ~~enforcement by the Bureau~~ of ~~Safety and Environmental Enforcement (“BSEE”) in~~ the ~~deepwater~~covenants ~~that~~under ~~increased~~ the ~~required~~2011 ~~scope of work~~Indenture.

~~Other~~Promissory ~~Income~~Note. On March 12, 2015, in connection with EGC’s issuance of the 11.0% Notes, we entered into a $325.0 million secured second lien promissory note between us, as the maker, and ~~Expense~~EGC, as the payee (the “Promissory Note”). 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.

~~Interest~~For ~~expense~~more ~~decreased~~information ~~approximately~~regarding ~~$5.1~~our ~~million~~outstanding ~~for the nine months ended March 31~~indebtedness, ~~2015,~~see asNote ~~compared~~5 — Indebtedness ~~to the nine months ended March 31, 2014 due primarily to a decrease~~ in ~~our effective interest rate on~~ the ~~8.25% Senior~~ Notes ~~from 9.1%~~ to ~~5.8%,~~Consolidated ~~reflecting~~Financial ~~the~~Statements ~~impact~~contained ~~of the fair value adjustment to the carrying amount of the 8.25% Senior Notes recorded~~ in ~~pushdown~~this ~~accounting.~~Quarterly ~~This decrease was partially offset by an increase in interest expense on our revolver debt, primarily due to the increase in revolver debt associated with the purchase of the SP49 Interests~~Report.

OtherBOEM incomeBonding (expense) in the nine months ended March 31, 2014 includes a net loss on derivative instruments of $68.5 million consisting of a loss of $65.1 million due to the change in fair value of derivative instruments which were to be settled in the future and a net loss of $3.4 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices. Prior to the Merger, we did not elect to designate derivative instruments as hedges. Requirements

~~Income~~As ~~Taxes~~of September 30, 2015, we had $180.8 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 OCS, approximately $58.3 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 bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on 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. Our total supplemental bonding results in an annual premium expense of approximately $2.7 million. 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, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM (which is reflected in the $58.3 million in lease and/or area bonds discussed above), and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $566.5 million of requested supplemental bonding was reduced by approximately $178 million.

~~The~~Since ~~income~~our ~~tax~~June ~~benefit~~2015 ~~for~~agreements with the ~~nine~~BOEM, ~~months~~we ~~ended~~have ~~March~~worked ~~31,~~towards ~~2015~~preparing isa ~~computed~~long-term ~~based~~financial onassurance ~~our~~plan ~~estimated~~that ~~annual~~we ~~effective~~could ~~tax/(benefit)~~submit ~~rate~~to ~~for~~ the ~~full~~BOEM ~~fiscal~~for ~~year~~approval. ~~This~~We ~~effective~~have ~~rate~~held ~~excludes~~meetings ~~the~~with ~~effect of~~ the ~~goodwill~~BOEM ~~impairment charge recorded~~ in ~~the~~furtherance ~~first quarter~~ of ~~fiscal~~the ~~2015~~plan’s ~~which~~development isand, ~~treated~~while as a ~~discrete~~version ~~item for purposes~~ of ~~computing our interim provision (benefit) for income taxes. The effective income tax/(benefit) rate (excluding~~ the ~~discrete item from pre~~long-~~tax~~term ~~book~~financial ~~loss)~~assurance ~~for~~plan ~~the~~could ~~nine~~be ~~months~~submitted ~~ended~~by ~~March~~November 3115, 2015, ~~was~~we ~~(36.6)%~~are ascurrently ~~compared~~seeking toa ~~101.3%~~30-day ~~for~~extension to the ~~nine~~November ~~months ended March 31~~15, ~~2014.~~2015 ~~The~~date ~~variance~~ in ~~the~~order ~~tax rate is primarily due~~ to ~~changes~~augment ~~in common permanent difference items. See Note 10, “Income Taxes” in~~ the ~~condensed~~final ~~consolidating~~plan ~~financial statements~~ in ~~Part~~light ~~1, Item 1~~ of ~~this~~new ~~Quarterly~~information ~~Report~~received.

36In October 2015, we received information from the BOEM indicating that, following November 15, 2015, we may 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-owners losing their exemptions. We believe a substantial portion of the additional supplemental financial assurance and/or bonding that may 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. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and address these potential additional liabilities. 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.

~~TABLE~~Consequently, OFas ~~CONTENTS~~we currently evaluate the information received from the BOEM in October 2015 and after taking into account items that we expect to be able to remove from our responsibility described above, we believe that the BOEM will assess an additional $125 to $200 million of supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued after November 15, 2015 if these

~~LIQUIDITY AND CAPITAL RESOURCES~~33

~~Overview~~TABLE OF CONTENTS

Asitems ofare ~~March~~not ~~31,~~otherwise ~~2015,~~addressed wein ~~had~~our ~~$150~~long-term ~~million~~financial inassurance ~~borrowings~~plan. ~~outstanding~~If ~~under~~we ~~the~~are ~~First~~successful ~~Lien~~in ~~Credit~~obtaining ~~Agreement,~~the as30-day ~~amended~~extension, towe ~~which~~intend wefor ~~are~~our ~~party~~long-term ~~with~~financial ~~EGC.~~assurance ~~Currently,~~plan weto ~~fund~~address ~~our~~these ~~operations~~additional ~~primarily~~financial ~~through~~assurance ~~cash~~requirements ~~flows~~for ~~from~~which ~~operating~~we ~~activities~~received ~~and~~information ~~advances~~in ~~from~~October ~~EGC~~2015. ~~Future~~Please ~~cash~~note ~~flows~~if ~~are~~our ~~subject~~co-lessees toand aus ~~number~~are ofunable ~~variables,~~to ~~including~~agree ~~the~~on ~~level~~allocation of ~~crude~~supplemental ~~oil~~financial ~~and~~assurance ~~natural gas production~~ and/or ~~prices.~~bonding ~~Prices~~amounts for ~~oil~~such ~~and~~specified ~~natural~~leases ~~gas~~and ~~began~~present tosuch ~~decline~~agreed ~~significantly~~upon ~~during~~allocations to the ~~fourth~~BOEM ~~quarter~~for ofapproval, ~~calendar~~the ~~2014~~BOEM ~~and~~may ~~have~~direct ~~continued~~supplemental tofinancial beassurance ~~volatile~~and/or ~~into~~bonding ~~calendar~~amounts ~~2015.~~for ~~These~~100% ~~declines~~of inthe ~~commodity~~lease ~~prices~~interests ~~have~~to ~~negatively impacted revenues~~us, ~~earnings and~~ ~~cash~~which ~~flows~~would ~~and~~substantially ~~sustained~~increase ~~low~~the ~~oil~~supplemental ~~and~~financial ~~natural~~assurance ~~gas prices could have a material~~ and/or ~~adverse~~bonding ~~effect on our liquidity position~~requirements.

~~Our~~Unrelated ~~Indebtedness~~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, ~~Available~~instead, ~~Credit~~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.

~~During~~While ~~March~~the ~~2015~~Draft Guidance, ~~the~~once ~~Tenth~~implemented ~~Amendment~~by to the ~~First~~BOEM, ~~Lien~~would ~~Credit~~allow ~~Agreement~~an ~~dated~~increased asnumber of ~~March~~operators ~~3, 2015~~ (~~the~~relative ~~“Tenth Amendment”) became effective. Pursuant~~ to ~~the~~those ~~terms~~operators ~~of the Tenth Amendment, the lenders~~ under the ~~First~~existing ~~Lien~~NTL ~~Credit~~regarding ~~Agreement~~supplemental ~~reduced~~financial ~~the~~assurance ~~borrowing~~and ~~base~~bonding) ~~for EGC from $1,500~~ to ~~$500~~self-insure ~~million,~~for oftheir ~~which~~decommissioning ~~such~~liabilities ~~amount~~that ~~$150 million~~ is ~~the~~no ~~borrowing~~more ~~base~~than ~~for~~10% ~~EPL (the “Revolving Credit Sub-Facility”). The maturity date~~ of ~~the~~their ~~First~~tangible ~~Lien~~net ~~Credit Agreement remains April 9~~worth, ~~2018,~~there ifis ~~certain~~no ~~conditions~~assurance ~~are~~that ~~met.~~the ~~Additionally,~~BOEM wewill ~~entered~~allow ~~into a $325 million secured second lien promissory note between~~ us, ~~as the maker, and EGC, as the payee (the “Promissory Note”) on March 12, 2015. Proceeds from the Promissory Note were used~~ to ~~repay~~utilize ~~a like amount of the outstanding borrowings under the Revolving Credit Sub~~self-~~Facility.~~insurance Asprograms ofand ~~March 31, 2015,~~ we ~~have~~currently ~~fully~~do ~~utilized~~not ~~amounts~~plan ~~available~~for ~~under our Revolving Credit Sub~~self-~~Facility.~~insurance ~~For~~under ~~more~~the ~~information on our Revolving Credit Sub~~long-~~Facility~~term ~~and~~financial ~~the~~assurance ~~Promissory~~plan ~~Note,~~that ~~see~~we ~~Note~~plan 7,to ~~“Indebtedness”~~submit into the ~~condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report~~BOEM.

~~The~~In ~~First~~addition ~~Lien~~to ~~Credit~~the ~~Agreement,~~Draft asGuidance ~~amended,~~describing ~~requires~~revised ~~EGC~~supplemental ~~and~~bonding ~~EPL~~procedures tothat ~~maintain~~may ~~certain~~be ~~financial~~used ~~covenants~~by ~~separately~~the ~~for~~bureau, ~~so long as~~ the ~~8.25%~~BOEM ~~Senior Notes remain outstanding. EGC~~ is ~~subject~~actively seeking to ~~the~~bolster ~~following~~its financial ~~covenant~~assurance onrequirements amandated ~~consolidated~~by ~~basis:~~rule afor ~~minimum~~all ~~current~~companies ~~ratio~~operating ofin nofederal ~~less than 1~~waters.0 toThe ~~1.0.~~cost Inof ~~addition,~~compliance ~~EGC~~with isour ~~subject~~existing tosupplemental ~~the~~bonding ~~following~~requirements, ~~financial~~including ~~covenants~~the ondirectives aissued ~~stand-alone~~by ~~basis:~~the ~~(a)~~BOEM ain ~~consolidated~~April ~~maximum~~2015 ~~net~~and ~~first~~June ~~lien~~2015, ~~leverage~~any ~~ratio~~other offuture ~~1.25~~directives, toor ~~1.0~~any ~~and~~other ~~(b)~~changes ato ~~consolidated~~the ~~maximum~~BOEM’s ~~net~~current ~~secured~~NTL ~~leverage~~supplemental ~~ratio~~bonding ofrequirements noor ~~more~~supplemental ~~than~~bonding ~~3.75~~regulations toapplicable ~~1.0. In addition, EPL is subject~~ to ~~the~~us ~~following~~or ~~financial~~our ~~covenants~~subsidiaries’ onproperties acould ~~stand-alone~~materially and ~~basis:~~adversely ~~(a)~~affect aour ~~consolidated~~financial ~~maximum~~condition, ~~first~~cash ~~lien~~flows, ~~leverage~~and ~~ratio~~results of 1operations.25 toIn ~~1.0~~addition, ~~and~~we ~~(b)~~may abe ~~consolidated~~required ~~maximum~~to ~~secured~~provide ~~leverage~~cash ~~ratio~~collateral ofor noletters ~~more~~of ~~than~~credit ~~3.75~~ to ~~1.0.~~support If the ~~EPL~~issuance ~~Notes~~of ~~are~~such nobonds ~~longer~~or ~~outstanding~~other ~~and~~surety. ~~certain~~Such ~~other~~letters ~~conditions~~of ~~are~~credit ~~met,~~would ~~EGC~~likely ~~will~~ be ~~subject~~issued tounder ~~the~~our ~~following~~credit ~~financial~~facility ~~covenants~~and onwould areduce ~~consolidated~~the ~~basis:~~amount ~~(a)~~of aborrowings ~~consolidated~~available ~~maximum~~under ~~net~~such ~~first~~facility ~~lien~~in ~~leverage~~the ~~ratio~~amount of ~~1.25~~any tosuch ~~1.0,~~letter ~~(b)~~of acredit ~~consolidated~~obligations. ~~maximum~~We ~~net~~can ~~secured~~provide ~~leverage~~no ~~ratio~~assurance ofthat nowe ~~more~~can ~~than~~continue ~~3.75~~ to ~~1.0,~~obtain ~~provided~~bonds ~~that~~or ifother ~~the~~surety ~~8.25%~~in ~~Senior~~all ~~Notes~~cases ~~are~~or ~~refinanced~~that ~~with~~we ~~new~~will ~~secured~~have ~~debt,~~sufficient ~~the~~availability ~~liens~~under ofour ~~which~~credit ~~are~~facility ~~junior~~to insupport ~~priority~~such tosupplemental ~~the~~bonding ~~Revolving~~requirements. ~~Credit~~If ~~Facility~~we ~~indebtedness,~~are ~~then~~unable ~~the~~to ~~maximum~~obtain ~~ratio~~the ~~permitted~~additional ~~would~~required bebonds ~~4.25~~or toassurances ~~1.0~~as requested, ~~and~~the ~~(c)~~BOEM amay ~~minimum~~require ~~current~~any ~~ratio~~ of noour ~~less~~operations ~~than~~on ~~1.0~~federal leases to ~~1.0.~~be Assuspended ofor ~~March 31~~terminated, ~~2015,~~and wesuch ~~were~~action incould ~~compliance~~have ~~with~~a ~~all~~material ofeffect ~~the~~on ~~covenants under~~ our ~~First~~business, ~~Lien~~prospects, ~~Credit~~results ~~Agreement. As a result~~ of ~~the Tenth Amendment~~operations, ~~we expect to remain in compliance with the~~ financial ~~covenants~~condition, ~~thereunder~~and ~~for the foreseeable future~~liquidity.

AsCapital a result of EGC’s reduction in borrowing base availability to $500 million and the resulting increased asset coverage for the Revolving Credit Facility, we do not currently anticipate any further borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, EGC’s borrowing base and our borrowing base under the Revolving Credit Sub-Facility may be further reduced, which would impact the working capital available to fund our capital spending program. In addition, we would be required to repay any outstanding indebtedness in excess of any reduced borrowing base. Expenditures

AtOur ~~March~~initial 31fiscal year 2016 capital budget is expected to be approximately $26 million. For the three months ended September 30, 2015, weour ~~had~~capital expenditures totaled approximately $~~510.0~~3 million, inof ~~aggregate~~which ~~principal~~approximately ~~amount~~$2 ~~outstanding~~million was spent on development of ~~our~~core 8properties and $1 million on other assets.~~25%~~ ~~Senior~~The ~~Notes~~budgeted ~~due~~capital ~~February~~is 15allocated to development activities, ~~2018~~which are geared toward the improvement of existing production, the continued development of core fields, and the performance of necessary plugging, abandonment and other decommissioning activities. ~~For~~We ~~more~~intend ~~information~~to onfund our ~~8.25%~~capital ~~Senior~~expenditures ~~Notes~~and contractual commitments, ~~see~~including ~~Note~~settlement 7of derivative contracts, ~~“Indebtedness”~~with incash ~~this~~flows ~~Quarterly~~from ~~Report~~operations and ~~Note~~borrowings 8and equity investments from EGC. If oil and natural gas prices remain at current levels or continue to decline, ~~“Indebtedness~~we may be required to reduce our capital expenditure budget for fiscal year 2016 and future years,” ofwhich in turn may affect our ~~2014~~liquidity ~~Transition~~and ~~Report~~results of operations in future periods. If our cash flows from operations and

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our ability to maintain and 34

37TABLE OF CONTENTS

~~TABLE~~availability OFof ~~CONTENTS~~funding from EGC are not sufficient to fund our capital program, we may 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.

grow reserves and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. For example, constraints in the credit markets may increase the rates we are charged for utilizing these markets. Based on our current production levels and prices for oil and natural gas, our liquidity and capital resource alternatives may not be sufficient to meet our funding requirements through March 31, 2016, without additional advances from EGC, further reductions in capital expenditures or sales of non-core assets by us or EGC. Disposition

~~Energy~~On ~~XXI~~June ~~and~~30, ~~its~~2015, ~~subsidiaries~~we ~~are~~sold ~~focused~~our oninterest ~~reducing~~in ~~leverage~~the ~~and~~East ~~are~~Bay ~~pursuing~~field ~~arrangements~~for ~~with~~cash ~~third~~consideration ~~parties~~of to$21 ~~monetize~~million ~~certain~~plus ~~midstream~~the ~~assets~~assumption of asset retirement obligations totaling approximately $55.1 ~~Additionally~~million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due during the quarter ended December 31, we2015. ~~may~~We ~~decide~~retained toa ~~divest~~5% ofoverriding ~~certain~~royalty ~~non-core~~interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets ~~from~~for ~~time~~a period not to ~~time.~~exceed ~~There~~5 ~~can~~years befrom nothe ~~assurance~~closing ~~any~~date or $7 million whichever occurs first, and we also retained 50% of ~~these~~the ~~discussions~~deep rights orassociated ~~transactions~~with ~~will~~the ~~prove~~East ~~successful~~Bay field.

As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), we maintain approximately $3.6 million in lease and/or area bonds issued to the BOEM that assures our commitment to comply with the terms and conditions of those leases. We ~~also~~may ~~maintain~~decide ~~approximately $122.5 million in bonds issued~~ to ~~predecessor~~divest ~~third party assignors~~ of certain ofnon-core ~~the~~assets ~~wells~~from ~~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~~time. InThere ~~April~~can ~~2015,~~be ~~we received letters from the BOEM stating that we~~ no ~~longer~~assurance ~~qualify~~any ~~for~~such ~~waiver of certain supplemental bonding requirements for~~ potential ~~offshore~~transactions ~~decommissioning,~~will ~~plugging~~prove ~~and abandonment liabilities~~successful. ~~The~~We ~~letters~~cannot ~~notified us that we must~~ provide ~~supplemental~~any ~~financial~~ assurance ~~and/or bonding for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements~~ that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $566.5 million, which amount is currently being negotiated by us. We are currently evaluating the impact of the BOEM letters on our future consolidated financial position, results of operations and cash flow. We intend to continue to work with the BOEM staff to resolve this matter, and we ~~have~~will ~~already~~be ~~undertaken~~able ~~a number of initiatives~~ to ~~mitigate~~sell our potential liability resulting from the waiver disqualification and to limit the amount of required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date as well as counting our existing bonds with third parties and certain letters of credit against the BOEM bonding request. The costs of satisfying these ~~supplemental~~assets bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, EGC may be required to provide letters of credit or other collateral on ~~our~~satisfactory ~~behalf to support the issuance of any required bonds or other surety. Such letters of credit would likely be issued by EGC under the Revolving Credit Facility~~terms, ~~which~~if ~~would~~at ~~reduce the amount of borrowings available to EGC under such facility in the amount of any such letter of credit obligations~~all. If we are unable to obtain the additional required bonds or assurances requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

CapitalCash ExpendituresFlows

~~For~~The ~~fiscal~~following ~~2015,~~table ~~our~~sets ~~capital~~forth ~~expenditures~~selected ~~are~~historical ~~now~~information ~~estimated~~from ~~at $250 million. For the nine months ended March 31, 2015,~~ our ~~capital~~statements ~~expenditures totaled approximately $228 million,~~ of ~~which~~cash ~~approximately~~flows: $157 million was spent on development of core properties, $30 million on exploration of core properties and $41 million on other assets. The budgeted capital is allocated to development activities, which are geared toward the improvement of existing production, the continued development of core fields, and the performance of necessary plugging, abandonment and other decommissioning activities.

We currently intend to fund our 2015 capital program and contractual commitments from cash flows from operations and advances and equity investments from EGC. If oil and natural gas prices remain at current levels or continue to decline, we may be required to reduce our capital expenditure budget in 2015 and the future, which in turn may affect our liquidity and results of operations in future periods. If our cash flows from operating activities and availability of funding from EGC are not sufficient to fund our capital program, we may further reduce our capital spending or otherwise fund our capital needs with proceeds from the sale of non-core assets. Our capital expenditures and the scope of our drilling activities for fiscal year 2015 may change as a result of several factors, including, but not limited to, changes in oil and natural gas sales prices,


	Three Months Ended September 30,
	2015			2014
	(In thousands)
Net cash provided by operating activities	$	15,936		$	62,848
Net cash used in investing activities		(13,120	)		(111,436	)
Net cash provided by (used in) financing activities		(3,033	)		43,010

38The decrease in our net cash provided by operating activities for the first quarter 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.

~~TABLE~~Net OFcash ~~CONTENTS~~used in investing activities decreased for the first quarter 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.

~~costs~~Net ofcash ~~drilling~~used ~~and~~in ~~completion~~financing ~~operations,~~activities ~~drilling~~for ~~results~~the ~~and~~first ~~changes~~quarter of fiscal 2016 primarily reflects $21.0 million in cash restricted related to the ~~borrowing~~sale ~~base~~of ~~under~~the East Bay field, offset by advances from EGC. Net cash provided by financing activities for the ~~First~~first ~~Lien~~quarter ~~Credit~~of ~~Agreement~~fiscal ~~and~~year ~~available~~2015 ~~funding~~reflects $43.0 million in advances from EGC.

~~Analysis~~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 ~~Cash~~directors. ~~Flows~~

TheContractual following table sets forth selected historical information from our statement of cash flows: Obligations

	Nine Months Ended March 31, 2015			Nine Months Ended March 31, 2014
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	90,344		$	258,023
Net cash used in investing activities		(271,904	)		(308,504	)
Net cash provided by financing activities		176,054			51,044

Our contractual obligations at September 30, 2015 did not change materially from those disclosed in Item 7 of our 2015 Annual Report, other than as disclosed in Note 5 — Indebtedness of Notes to Consolidated Financial Statements in this Quarterly Report.

TheCritical decreaseAccounting in our fiscal year 2015 cash flows from operating activities primarily reflects decreases in revenues due to the decrease in oil prices and changes in working capital during the nine months ended March 31, 2015, as compared to the nine months ended March 31, 2014. Policies

~~Net~~Our ~~cash~~significant ~~used~~accounting inpolicies ~~investing~~are ~~activities~~summarized ~~decreased~~in ~~for~~Note ~~the~~1 — Organization ~~nine~~and ~~months~~Summary ~~ended~~of ~~March~~Significant ~~31,~~Accounting ~~2015,~~Policies asof ~~compared~~Notes to ~~the~~Consolidated ~~nine~~Financial ~~months~~Statements ~~ended~~included ~~March 31, 2014, primarily due to a reduction~~ in ~~cash~~our ~~used~~2015 ~~for~~Annual ~~acquisitions, partially offset by a slight increase in capital expenditures~~Report.

Net cash provided by financing activities during the nine months ended March 31, 2015 reflects $177.8 million in advances from EGC. Net cash provided by financing activities during the nine months ended March 31, 2014 reflects $55.0 million of borrowings under our prior senior credit facility as well as settlements of purchases of shares of our common stock (which had been kept as treasury shares) pursuant to our repurchase program. 35

WeTABLE ~~have~~OF 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. CONTENTS

NewRecent Accounting Pronouncements

For information regarding new accounting pronouncements, see the information in Note 1~~, “~~ — Organization and ~~Basis~~Summary of ~~Presentation~~Significant Accounting Policies — Recent Accounting Pronouncements,” inof ~~the~~Notes ~~condensed~~to ~~consolidated~~Consolidated ~~financial~~Financial ~~statements~~Statements in ~~Part 1, Item 1 of~~ 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 ~~2014~~2015 ~~Transition~~Annual Report.

We are exposed to a variety of market risks including ~~credit risk,~~ 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 ~~are~~were a party at ~~March~~September 3130, 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.

39Commodity Price Risk

~~TABLE~~Our OFmajor ~~CONTENTS~~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.

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 ~~Risk~~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. Given EGC’s current borrowing base at $500 million and the resulting asset coverage for the Revolving Credit Facility, we do not currently anticipate any borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, the borrowing base under the Revolving Credit Facility may be further reduced, which would require EGC and us to repay that portion, if any, of our outstanding indebtedness under the facility in excess of the new 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.

We ~~monitor~~utilize ~~our risk of loss due to non~~commodity-~~performance~~based byderivative ~~counterparties~~instruments ofwith ~~their~~major ~~contractual~~financial ~~obligations.~~institutions ~~Our~~to ~~principal~~reduce exposure to ~~credit~~fluctuations ~~risk~~in ~~is through~~ the ~~sale~~price of ~~our~~crude oil and natural gas. ~~production,~~We ~~which~~also weuse ~~market~~financially tosettled ~~energy~~crude ~~marketing~~oil ~~companies~~ and ~~refineries~~natural ~~and~~gas toputs, aput ~~lesser~~spreads, ~~extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings~~swaps, ~~financial~~zero-cost ~~statements~~collars and ~~payment~~three-way ~~history~~collars. WeAny ~~extend~~gains ~~credit~~or ~~terms~~losses ~~based~~resulting onfrom ~~our~~the ~~evaluation~~change ofin ~~each~~fair ~~counterparty’s~~value ~~creditworthiness.~~from ~~Although~~hedging wetransactions ~~have~~and ~~not~~from ~~generally~~the ~~required~~settlement ~~our~~of ~~counterparties~~hedging tocontracts ~~provide~~are ~~collateral~~recorded ~~to support their obligation to us, we may, if circumstances dictate, require collateral~~ in ~~the~~earnings ~~future.~~as Ina ~~this~~component ~~manner,~~of ~~we reduce credit risk~~revenues.

~~Commodity~~With ~~Price~~a ~~Risk~~financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost

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. 36

~~Prices~~TABLE ~~also~~OF 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 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. As a result of the reduction in EGC’s borrowing base availability to $500 million and the resulting increased asset coverage for the Revolving Credit Facility, we do not currently anticipate any further borrowing base reductions in connection with the semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, the borrowing base under the Revolving Credit Facility may be further reduced, which would require EGC and us to repay that portion, if any, of our outstanding indebtedness under the facility in excess of the new 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. CONTENTS

Wecollar, ~~utilize~~the ~~commodity-based~~counterparty ~~derivative~~is ~~instruments~~required ~~with~~to ~~major~~make ~~financial~~a ~~institutions~~payment to ~~reduce~~us ~~exposure~~if tothe ~~fluctuations~~settlement inprice for any settlement period is below the floor price of ~~crude~~the ~~oil~~collar, and ~~natural~~we ~~gas.~~are Werequired ~~also~~to ~~use~~make ~~financially~~a ~~settled~~payment ~~crude~~to ~~oil~~the ~~and~~counterparty ~~natural~~if ~~gas~~the ~~puts,~~settlement ~~put~~price ~~spreads,~~for ~~swaps,~~any ~~zero-cost~~settlement ~~collars~~period ~~and~~is above the cap price for the collar. A three-way ~~collars~~collar is a combination of options consisting of a sold call, a purchased put and a sold put. ~~Any~~The ~~gains~~sold orcall ~~losses~~establishes ~~resulting~~a ~~from~~maximum price we will receive for the ~~change~~volumes inunder ~~fair~~contract. ~~value~~The ~~from~~purchased ~~hedging~~put ~~transactions~~establishes ~~that~~a ~~are~~minimum ~~determined~~price tounless bethe ~~ineffective~~market ~~are~~price ~~recorded~~falls inbelow ~~income~~the sold put, ~~whereas~~at ~~gains~~which ~~and~~point ~~losses~~the ~~from~~minimum price would be the reference ~~settlement~~price of(i.e., ~~hedging~~NYMEX ~~contracts~~WTI ~~are~~and/or ~~recorded~~BRENT, inIPE) ~~crude~~plus ~~oil~~the difference between the purchased put and ~~natural~~the ~~gas~~sold ~~revenues~~put strike price.

~~With~~At aSeptember ~~financially~~30, ~~settled purchased put~~2015, ~~the~~our ~~counterparty~~crude isoil ~~required~~contracts tooutstanding ~~make~~were ain ~~payment~~an toasset usposition ~~if the settlement price for any settlement period is below the hedged price~~ of ~~the~~$1.5 ~~transaction~~million. A ~~put~~10% ~~spread~~increase isin acrude ~~combination~~oil ofprices awould ~~bought~~reduce ~~put and a sold put. If~~ the ~~settlement~~fair ~~price~~value isby ~~below~~approximately ~~the~~$0.8 ~~sold put strike price~~million, wewhile ~~receive~~a ~~the~~10% ~~difference~~decrease ~~between~~in ~~the~~crude ~~two~~oil ~~strike~~ prices. Ifwould ~~the~~increase ~~settlement price is below~~ the ~~bought~~fair ~~put~~value ~~strike~~by ~~price~~approximately ~~but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price~~$1.7 ~~There is no settlement if the underlying price settles above the bought put strike price~~million. ~~With~~At aSeptember ~~swap~~30, ~~the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction~~2015, ~~and~~our wenatural ~~are~~gas ~~required~~contract tooutstanding ~~make~~was ain ~~payment~~an toasset ~~the~~position ~~counterparty~~of if$0.5 ~~the settlement price for any settlement period is above the hedged price for the transaction~~million. ~~With~~A a10% ~~zero-cost~~increase ~~collar,~~in ~~the~~natural ~~counterparty~~gas isprices ~~required~~would toreduce ~~make a payment to us if~~ the ~~settlement~~fair ~~price~~value ~~for~~by ~~any~~approximately ~~settlement~~$0.1 ~~period is below the floor price of the collar~~million, ~~and~~while ~~we are required to make~~ a ~~payment~~10% todecrease ~~the~~in ~~counterparty~~natural ifgas ~~the~~prices ~~settlement~~would ~~price~~increase ~~for any settlement period is above~~ the ~~cap~~fair ~~price~~value ~~for~~by ~~the~~approximately ~~collar~~$0.1 ~~A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put~~million. ~~The~~These ~~sold~~fair ~~call~~value ~~establishes~~changes aassume volatility ~~maximum~~based ~~price~~on weprevailing ~~will receive for the volumes under contract. The purchased put establishes a minimum price unless the~~ market ~~price~~parameters ~~falls below the sold put,~~ at ~~which~~September ~~point the minimum price would be the reference price (i.e.~~30, ~~NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price~~2015.

AtOur ~~March~~ultimate ~~31,~~realized ~~2015,~~gain ~~our~~or ~~crude~~loss ~~oil~~with ~~contracts~~respect ~~outstanding~~to ~~had~~commodity anprice ~~asset~~fluctuations ~~position~~will ofdepend ~~$1.3~~on ~~million. A 10% increase in crude oil prices would reduce~~ the ~~fair~~future ~~value~~exposures bythat ~~approximately~~arise ~~$2.9~~during ~~million, while a 10% decrease in crude oil prices would increase~~ the ~~fair value by approximately $2.4 million. At March 31~~period, ~~2015,~~ our ~~natural~~hedging ~~gas~~strategies ~~contract~~at ~~outstanding~~the ~~was~~time inand ancommodity ~~asset~~prices ~~position~~at ofthe $1time.6 ~~million. A 10% increase in natural gas prices~~

40For a complete discussion of our derivative financial instruments, see Note 6 — Derivative Financial Instruments of Notes to Consolidated Financial Statements in this Quarterly Report.

TABLEInterest OFRate CONTENTSRisk

~~would~~Our ~~reduce~~exposure ~~the~~to ~~fair~~changes ~~value~~in byinterest ~~approximately~~rates $0relates primarily to our variable rate debt obligations.3 ~~million~~Specifically, ~~while~~we aare ~~10%~~exposed ~~decrease~~to changes in ~~natural~~interest ~~gas~~rates ~~prices~~as ~~would~~a ~~increase~~result ~~the~~of ~~fair~~borrowings ~~value~~under byour ~~approximately~~Revolving Credit Sub-Facility. As of September 30, 2015, total debt included $0150.30 million of floating-rate debt. ~~These~~As ~~fair~~a ~~value~~result, ~~changes~~our ~~assume~~period-end ~~volatility~~interest costs will fluctuate based on ~~prevailing~~short-term ~~market~~interest ~~parameters~~rates aton ~~March~~approximately 3115% of our total debt outstanding as of September 30, 2015. ~~For~~A a10% ~~complete~~change ~~discussion~~in offloating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $7,238. We currently have no interest rate hedge positions in place to reduce our ~~derivative~~exposure ~~financial~~to ~~instruments~~changes in interest rates. However, ~~see~~to ~~Note~~reduce 8our future exposure to changes in interest rates, ~~“Derivative~~we ~~Financial~~may ~~Instruments”~~utilize ofinterest ~~the~~rate ~~condensed~~derivatives ~~consolidated~~to ~~financial~~alter ~~statements~~interest rate exposure in ~~Part~~an I,attempt ~~Item~~to 1reduce ofinterest ~~this~~rate ~~Quarterly~~expense ~~Report~~related to existing debt issues.

~~Our~~Item ~~ultimate~~4. ~~realized~~CONTROLS ~~gain~~AND ~~or loss with respect to commodity price fluctuations will depend on the future exposures that arise during the period, our hedging strategies at the time and commodity prices at the time~~PROCEDURES.

InterestEvaluation Rateof RiskDisclosure Controls and Procedures

~~Our~~Under ~~exposure~~the tosupervision ~~changes~~and inwith ~~interest~~the ~~rates~~participation ~~relates~~of ~~primarily~~our tomanagement, including our ~~variable~~principal ~~rate~~executive ~~debt~~officer ~~obligations.~~and ~~Specifically~~our principal financial officer, we ~~are~~evaluated ~~exposed~~the toeffectiveness ~~changes~~of inthe ~~interest~~design ~~rates~~and asoperation aof ~~result~~our ofdisclosure ~~borrowings~~controls ~~under~~and ~~our~~procedures ~~Revolving~~(as ~~Credit~~defined ~~Sub~~in Rules 13a-~~Facility.~~15(e) Asand of15d-15(e) ~~March~~to ~~31,~~the ~~2015~~Securities Exchange Act of 1934, ~~total~~as ~~debt~~amended ~~included~~(the ~~$150.0~~“Exchange ~~million~~Act”)) as of ~~floating-rate~~the ~~debt~~end of the period covered by this Quarterly Report. AsOur adisclosure ~~result,~~controls ~~our~~and ~~period-end~~procedures ~~interest~~are ~~costs~~designed ~~will~~to ~~fluctuate~~provide ~~based~~reasonable onassurance ~~short-term~~that ~~interest~~the ~~rates~~information onrequired ~~approximately~~to ~~15%~~be ofdisclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our ~~total~~management, ~~debt~~including ~~outstanding~~our principal executive officer and principal financial officer, as ofappropriate, ~~March~~to 31allow timely decisions regarding required disclosure and is recorded, ~~2015.~~processed, Asummarized 10and ~~percent~~reported ~~change~~within the time periods specified in ~~floating~~the ~~interest~~rules ~~rates~~and forms of the SEC. Based on ~~period-end~~this ~~floating~~evaluation ~~debt~~and ~~balances~~as ~~would~~a ~~change~~result ~~quarterly~~of ~~interest~~material ~~expense~~weakness byidentified ~~approximately~~during ~~$6,750.~~preparation Weof ~~currently have~~the noCompany’s ~~interest~~financial ~~rate~~statements ~~hedge~~for ~~positions~~the infiscal ~~place~~year toended ~~reduce~~June ~~our~~30, ~~exposure~~2015 towhich ~~changes~~has innot ~~interest~~been ~~rates.~~fully ~~However~~remediated, toour ~~reduce~~principal ~~our~~executive ~~future~~officer ~~exposure~~and toprincipal ~~changes~~financial inofficer ~~interest~~have ~~rates,~~concluded wethat ~~may~~our ~~utilize~~disclosure ~~interest~~controls ~~rate~~and ~~derivatives~~procedures towere ~~alter~~not ~~interest~~effective ~~rate~~at ~~exposure~~the inreasonable anassurance ~~attempt~~level toas ~~reduce~~of ~~interest~~the ~~rate~~end ~~expense~~of ~~related~~the toperiod ~~existing~~covered ~~debt~~by ~~issues~~this Quarterly Report.

ItemChanges 4.in CONTROLSInternal ANDControl PROCEDURES.over Financial Reporting

~~(a)~~During ~~Quarterly~~the ~~Evaluation~~quarter ended September 30, 2015, Energy XXI’s board of ~~Disclosure~~directors ~~Controls~~began the process of designing and ~~Procedures~~implementing 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

Disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. This information is also accumulated and communicated to management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, under the supervision and with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the most recent fiscal quarter reported on herein. Based on that evaluation, our principal executive officer and principal financial officer in conjunction with changes in internal controls over financial reporting as noted below concluded that our disclosure controls and procedures were effective as of March 31, 2015. 37

~~Because~~TABLE ofOF their inherent limitations, disclosure controls and procedures may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that such controls and procedures may become inadequate because of changes in conditions, or that the degree of compliance with the controls or procedures may deteriorate. Accordingly, even effective disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. CONTENTS

address any potential conflicts of interest that could arise between Energy XXI and any of its vendors; revising Energy XXI’s Code of Business Conduct and Ethics to explicitly ban any personal loans from Energy XXI’s vendors (b)other ~~Changes~~than ordinary course loans from financial institutions) in ~~Internal~~the ~~Control~~future; ~~Over~~and ~~Financial~~implementing ~~Reporting~~an enhanced comprehensive training program on Energy XXI’s Code of Business Conduct and Ethics.

~~Effective~~Other ~~January~~than 1,changes ~~2015~~related to the items noted above, ~~all~~there was no change in our system of ~~EPL’s~~internal ~~controls~~control ~~including~~over ~~controls~~financial ~~related~~reporting to(as ~~information~~such ~~technology~~term is defined in Rules 13a-15(f) and ~~accounting~~15d-15(f) ~~systems~~under ~~were~~the ~~transitioned~~Exchange Act) during our quarterly period ended September 30, 2015 that has materially affected, or is reasonably likely to ~~Energy~~materially ~~XXI’s~~affect, our internal control ~~environment~~over financial reporting.

Other than the change noted above, there were no changes in our internal controls 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 March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. 38

41TABLE OF CONTENTS

TABLE OF CONTENTS

PART II — OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS.

~~For~~We ~~information~~are ~~regarding~~involved in various legal proceedings, ~~see~~and ~~the information in Note 12~~claims, ~~“Commitments~~which ~~and~~arise ~~Contingencies”~~ in the ~~condensed~~ordinary ~~consolidated~~course ~~financial~~of ~~statements~~our inbusiness. ~~Part~~We I,do ~~Item~~not 1believe ofthe ~~this~~ultimate ~~Quarterly~~resolution ~~Report,~~of ~~which~~any issuch ~~incorporated~~actions bywill ~~reference~~have ~~into~~a ~~Part~~material ~~II,~~effect ~~Item~~on 1our offinancial ~~this~~position ~~Quarterly~~or ~~Report~~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, please refer to Part I, “Item 1A. — Risk Factors” in our ~~2014~~2015 ~~Transition~~Annual Report. There have been no material changes in the risk factors set forth in our ~~2014~~2015 ~~Transition Report~~Annual ~~other than those set forth below~~Report.

~~Oil~~Item ~~and~~2. ~~natural~~UNREGISTERED ~~gas~~SALES ~~prices~~OF ~~are~~EQUITY ~~volatile,~~SECURITIES ~~and~~AND aUSE ~~substantial~~OF ~~or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth~~PROCEEDS.

~~Oil~~None and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil prices declined severely during the second quarter of our 2015 fiscal year with continued lower prices in the third fiscal quarter of 2015. The WTI crude oil price per barrel for the period from January 1, 2014 to March 31, 2015 ranged from a high of $107.95 to a low of $43.39, a decrease of 59.8%, and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to March 31, 2015 ranged from a high of $6.15 to a low of $2.50, a decrease of 59.3%. As of April 30, 2015, the spot market price for WTI was $59.63. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

•Item ~~domestic~~3. ~~and~~DEFAULTS ~~foreign~~UPON ~~supplies~~SENIOR ~~of oil and natural gas;~~SECURITIES.

•None ~~price and quantity of foreign imports of oil and natural gas;~~

•Item ~~actions~~4. ofMINE ~~the~~SAFETY ~~Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;~~DISCLOSURES.

•Not ~~level~~applicable ~~of consumer product demand, including as a result of competition from alternative energy sources;~~

•Item ~~level~~5. ofOTHER ~~global oil and natural gas exploration and production activity;~~INFORMATION.

•None ~~domestic and foreign governmental regulations;~~

•Item ~~level~~6. ~~of global oil and natural gas inventories;~~EXHIBITS.

•The ~~political~~exhibits ~~conditions~~listed inon orthe ~~affecting~~accompanying ~~other~~Exhibit ~~oil-producing~~Index ~~and~~are ~~natural~~filed ~~gas-producing~~or ~~countries,~~incorporated ~~including~~by ~~the~~reference ~~current~~as ~~conflicts~~part inof ~~the~~this ~~Middle~~Quarterly ~~East~~Report, and ~~conditions~~such inExhibit ~~South~~Index ~~America~~is ~~and~~incorporated ~~Russia;~~herein by reference.

~~• weather conditions;~~39

•TABLE ~~technological~~OF ~~advances affecting oil and natural gas production and consumption;~~CONTENTS

• overall U.S. and global economic conditions; and

• price and availability of alternative fuels.

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. The speed and severity of the decline in oil prices during the second quarter of our 2015 fiscal year and the continued lower prices in the third fiscal quarter of our fiscal year 2015 has materially affected our results of operations. Any sustained periods of low prices for oil or natural gas are likely to materially and adversely affect our financial position, the quantities of natural

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gas and oil reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds from EGC and EGC’s ability to access funds under the Revolving Credit Facility and through the capital markets.

EGC’s Revolving Credit Facility and our Revolving Credit Sub-Facility have substantial restrictions and financial covenants which we or EGC may not be in compliance with in future periods. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.

We depend on EGC and the Revolving Credit Facility for a portion of our future capital needs. The amount available for borrowing under the Revolving Credit Facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. If oil and natural gas commodity prices were to decline significantly from current levels, the borrowing base under the Revolving Credit Facility may be reduced. As a result, we may be unable to obtain adequate funding from EGC or under the Revolving Credit Facility or even be required to pay down amounts outstanding under our Revolving Credit Facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our exploration and development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.

The Revolving Credit Facility and the Revolving Credit Sub-Facility restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We also are, and expect to continue to be, required to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations 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 fiscal 2015, and we continue to experience a low commodity price environment.

We and EGC have been asked by the U.S. Bureau of Ocean Energy Management (the “BOEM”) to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available to EGC under the Revolving Credit Facility.

To cover the various obligations of lessees on the OCS of the Gulf of Mexico, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. We maintain approximately $3.6 million in lease and/or area bonds issued to the BOEM that assures our commitment to comply with the terms and conditions of those leases. We also maintain approximately $122.5 million in bonds issued to predecessor third party assignors of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that we no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that we much provide supplemental financial assurance and/or bonding for our offshore oil and gas leases, rights-of-way, and rights-of-use and easements that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $566.5 million, which amount is currently being negotiated by us. We are currently evaluating the impact of the BOEM letters on our future consolidated financial position, results of operations and cash flow. We intend to continue to work with the BOEM staff to resolve this matter, and we have already undertaken a number of initiatives to mitigate our potential liability resulting from the waiver disqualification and to limit the amount of required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date as well as counting our existing bonds with third parties and certain letters of credit against the BOEM bonding request. However, EGC may be required to provide letters of credit or other collateral on our behalf to support the issuance of any required bonds or other surety. Such letters of credit would likely be issued by EGC under the Revolving Credit Facility, which would reduce the amount of borrowings available to EGC under such facility in the amount of any such letter of credit obligations. If we are unable to obtain the additional required bonds or assurances requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

None

Item 3. DEFAULTS UPON SENIOR SECURITIES.

None

Item 4. MINE SAFETY DISCLOSURES.

None

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: ~~May~~November 1513, 2015 By:/s/ Rick D. FoxRick D. FoxChief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

4540

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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	Secured Second Lien Promissory Note, dated as of March 12, 2015, issued by EPL Oil & Gas, Inc., as the Maker, in favor of Energy XXI Gulf Coast, Inc., as the Payee	8-K	001-16179	10.1	3/18/2015
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
10.2	Guaranty, dated as of March 12, 2015, issued by the subsidiaries of EPL Oil & Gas, Inc., in favor of Energy XXI Gulf Coast, Inc., as Lender	8-K	001-16179	10.2	3/18/2015
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
10.3	Second Lien Pledge and Security Agreement and Irrevocable Proxy, dated as of March 12, 2015, by EPL Oil & Gas, Inc. and each Subsidiary Guarantor Party thereto, in favor of Energy XXI Gulf Coast, Inc., as Lender	8-K	001-16179	10.3	3/18/2015
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

4641

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Exhibit Number

Exhibit Description

Incorporated by Reference Form

SEC File Number

Exhibit

Filing Date

Filed/ Furnished Herewith

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

101.INS*

XBRL Instance Document

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

101.SCH*

XBRL Taxonomy Extension Schema Document

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

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

101.INS

XBRL Instance Document

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.PRE*

XBRL Taxonomy Extension Presentation 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

47* 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 CONDENSED CONSOLIDATED BALANCE SHEETS (In thousands, except share data)

EPL OIL & GAS, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) (In thousands, except per share data)

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

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

(1) Organization and Summary of Significant Accounting Policies

(12) OrganizationPushdown Accounting and Basis of Presentation – (continued)Goodwill

6(2) Pushdown Accounting and Goodwill – (continued)

The(3) followingProperty table summarizes the assets acquired and liabilities assumed in the transfer. Equipment

The Nexen Acquisition

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

The(3) WestProperty Deltaand 29Equipment Acquisition– (continued)

TABLE(4) OFAsset CONTENTSRetirement Obligations

(2) Acquisitions – (continued)

Results(5) of Operations and Pro Forma InformationIndebtedness

WeRevolving haveCredit determined that the presentation of net income attributable to the acquired interests and properties is impracticable due to the integration of the related operations upon acquisition. Sub-Facility

b.EPL IncreaseOIL DD&A expenseGAS, by $25INC.0 millionAND andSUBSIDIARIES $82.6NOTES million,TO respectively,CONSOLIDATED toFINANCIAL correspondSTATEMENTS with the full cost method of accounting.(UNAUDITED)

c. Decrease interest expense $3.4 million and $10.0 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of our 8.25% senior notes due February 2018 (the5) “8.25%Indebtedness Senior– Notes”(continued).

(3)EPL PushdownOIL Accounting& andGAS, GoodwillINC. –AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continuedUNAUDITED)

corresponding(5) increaseIndebtedness in– goodwill of approximately $2.1 million; accordingly the June 30, 2014 condensed consolidated balance sheet has been retrospectively adjusted to increase the value of goodwill. (continued)

TABLEDerivative OFInstruments CONTENTSPremium Financing

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

The(5) followingIndebtedness table– indicates the number of shares underlying outstanding stock-based awards excluded from the computation of dilutive weighted average shares because their effect was antidilutive for the period indicated. (continued)

Interest Expense

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

(6) Asset Retirement Obligations

(7) Indebtedness

Revolving Credit Sub-Facility

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

(7) Indebtedness – (continued)

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

(7) Indebtedness – (continued)

Promissory Note

8.25% Senior Notes

Derivative Instruments Premium Financing

(8) Derivative Financial Instruments

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

(8) Derivative Financial Instruments – (continued)

Oil Contracts

Gas Contracts

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

(86) Derivative Financial Instruments – (continued)

(97) Fair Value Measurements

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

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

18(9) Related Party Transactions

(1110) RelatedCommitments Partyand Transactions – (continued)Contingencies

On(10) JanuaryCommitments 16,and 2015,Contingencies Plaintiffs– filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice. (continued)

adjustmentsEPL mayOIL be& material. When they occurGAS, theseINC. adjustmentsAND areSUBSIDIARIES recordedNOTES inTO theCONSOLIDATED currentFINANCIAL period,STATEMENTS which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. (UNAUDITED)

SUCCESSOR(11) COMPANY Supplemental Condensed Consolidating BalanceFinancial Sheet As of March 31, 2015 (UNAUDITED)Information

SUCCESSOREPL COMPANYOIL Supplemental& CondensedGAS, ConsolidatingINC. BalanceAND SheetSUBSIDIARIES AsNOTES ofTO JuneCONSOLIDATED 30,FINANCIAL 2014STATEMENTS (AUDITEDUNAUDITED)

(11) Supplemental Condensed Consolidating Financial Information – (continued)

23EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance Sheet As of September 30, 2015 (UNAUDITED)

24EPL OIL & GAS, INC. Supplemental Condensed Consolidating Balance Sheet As of June 30, 2015 (AUDITED)

25EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Operations Three Months Ended September 30, 2015 (UNAUDITED)

26EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Operations Three Months Ended September 30, 2014 (UNAUDITED)

27EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash Flows Three Months Ended September 30, 2015 (UNAUDITED)

28EPL OIL & GAS, INC. Supplemental Condensed Consolidating Statement of Cash Flows Three Months Ended September 30, 2014 (UNAUDITED)

dispositionKnown ofTrends oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Uncertainties

(1)Results For the three and nine months ended March 31, 2015, our oil and natural gas revenues and resulting average sales prices include the impact of accounting for our derivative financial instruments as cash flow hedges.Operations

32Three Months Ended September 30, 2015 Compared to Three Months Ended September 30, 2014

ThreeRevenue Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014Variances

Overview

RevenuePrice and Volume Variances

NM — NotVolume meaningful. Variances

33Costs and Expenses and Other (Income) Expense

Income Taxes

34Liquidity and Capital Resources

TABLE OF CONTENTSOverview

CapitalCash ExpendituresFlows

TheContractual following table sets forth selected historical information from our statement of cash flows: Obligations

NewRecent Accounting Pronouncements

General

39Commodity Price Risk

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

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)

Filing Compare · EPL OIL & GAS, INC.