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 31, 2015
or


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

Commission file number: 001-16179

EPL Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)


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


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

(713) 351-3000

Registrant’s telephone number, including area code

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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.

TABLE OF CONTENTS


	Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements:
Condensed Consolidated Balance Sheets as of March 31, 2015 (Unaudited) and June 30, 2014		1
Condensed Consolidated Statements of Operations (Unaudited) for the three and nine months ended March 31, 2015 and 2014		2
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) for the three and nine months ended March 31, 2015		3
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		42
Item 1A. Risk Factors		42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		44
Item 3. Defaults Upon Senior Securities		44
Item 4. Mine Safety Disclosures		44
Item 5. Other Information		44
Item 6. Exhibits		44

TABLE OF CONTENTS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this quarterly report on Form 10-Q (the “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 current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. 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;

•

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

•

hedging activities exposing us to pricing and counterparty risk;

•

uncertainties in estimating our oil and gas reserves;

•

replacing our oil and gas reserves;

•

uncertainties in exploring for and producing oil and gas;

•

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

•

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

•

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

•

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.

TABLE OF CONTENTS

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 they are made, whether as a result of new information, future events or otherwise.

iii

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS.

EPL OIL & GAS, INC. AND SUBSIDIARIES

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


	March 31, 2015			June 30, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	95		$	5,601
Trade accounts receivable – net		53,992			72,301
Derivative financial instruments		2,906			—
Deferred tax asset		16,760			24,587
Prepaid expenses		6,135			26,521
Total current assets		79,888			129,010
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
Goodwill		—			329,293
Restricted cash		6,024			6,023
Other assets and debt issuance costs, net of accumulated amortization		1,068			317
Total assets	$	2,140,514		$	3,669,830
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	30,398		$	92,981
Due to EGC		182,792			4,960
Accrued liabilities		72,397			161,518
Asset retirement obligations		39,831			39,831
Derivative financial instruments		—			26,440
Current maturities of long-term debt		3,176			—
Total current liabilities		328,594			325,730
Long-term debt, less current maturities		692,855			1,025,566
Intercompany promissory note		325,000			—
Asset retirement obligations		214,355			232,864
Deferred tax liabilities		49,308			483,798
Derivative financial instruments		—			2,140
Other		—			6
Total liabilities		1,610,112			2,070,104
Commitments and contingencies (Note 12)
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	)
Retained earnings (accumulated deficit)		(1,072,729	)		6,637
Total stockholder’s equity		530,402			1,599,726
Total liabilities and stockholder’s equity	$	2,140,514		$	3,669,830

See accompanying notes to condensed consolidated financial statements.

TABLE OF CONTENTS

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 March 31, 2015			Nine Months Ended March 31, 2015			Three Months Ended March 31, 2014			Nine Months Ended March 31, 2014
Revenue:
Oil and natural gas	$	87,253		$	417,043		$	158,470		$	483,229
Other		—			932			1,021			2,864
Total revenue		87,253			417,975			159,491			486,093
Costs and expenses:
Lease operating		49,571			161,175			41,734			123,203
Transportation		543			2,317			900			3,125
Exploration expenditures and dry hole costs		—			—			4,941			23,033
Impairment of oil and natural gas properties		430,859			1,113,727			61			827
Goodwill impairment		—			329,293			—			—
Depreciation, depletion and amortization		73,576			235,868			45,645			146,146
Accretion of liability for asset retirement obligations		5,509			17,788			6,997			23,098
General and administrative		11,998			26,850			10,287			23,923
Taxes, other than on earnings		3,057			7,529			2,472			8,363
Gain on sales of assets		—			—			—			(1,825	)
Other		(3	)		18			(942	)		27,457
Total costs and expenses		575,110			1,894,565			112,095			377,350
Income (loss) from operations		(487,857	)		(1,476,590	)		47,396			108,743
Other income (expense):
Interest income		6			10			10			82
Interest expense		(12,558	)		(34,406	)		(13,304	)		(39,479	)
Loss on derivative instruments		(579	)		(635	)		(13,142	)		(68,482	)
Total other expense		(13,131	)		(35,031	)		(26,436	)		(107,879	)
Income (loss) before income taxes		(500,988	)		(1,511,621	)		20,960			864
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 to condensed consolidated financial statements.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
(UNAUDITED)
(In thousands)


	Three Months Ended March 31, 2015			Nine Months Ended March 31, 2015
Net loss	$	(310,517	)	$	(1,079,366	)
Other comprehensive income (loss)
Crude oil and natural gas cash flow hedges
Unrealized change in fair value net of ineffective portion		(954	)		43,220
Effective portion reclassified to earnings during the period		(2,510	)		(27,586	)
Total other comprehensive income (loss)		(3,464	)		15,634
Deferred income tax expense (benefit)		(1,282	)		5,592
Net other comprehensive income (loss)		(2,182	)		10,042
Comprehensive loss	$	(312,699	)	$	(1,069,324	)

See accompanying notes to condensed consolidated financial statements.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED 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

See accompanying notes to condensed consolidated financial statements.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(1) Organization and Basis of Presentation

Nature of Operations. EPL Oil & Gas, Inc. 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, which is an indirect wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of Bermuda (“Energy XXI”). References in this Quarterly Report to “we,” “our,” “us,” “the Company” or “EPL”) are to EPL Oil & Gas, Inc. and its wholly-owned subsidiaries. We operate as an independent oil and natural gas exploration and production company with current operations concentrated in the U.S. Gulf of Mexico shelf (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.

The Merger resulted in EPL becoming an indirect, wholly-owned subsidiary of Energy XXI. Therefore, in the preparation of our financial statements, we have applied “pushdown” accounting, based on guidance from the Securities and Exchange Commission (“SEC”). Pushdown accounting refers to the use of the acquiring entity’s basis of accounting in the preparation of the acquired entity’s financial statements. 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.

Energy XXI follows the “full cost” method of accounting for its oil and gas producing activities, while we had historically followed the “successful efforts” method of accounting. Subsequent to the Merger, we converted our 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.

The accompanying consolidated financial statements include the accounts of EPL and its 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.

Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(1) Organization and Basis of Presentation – (continued)

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 2014 Transition Report.

Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in 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.

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

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

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(2) Acquisitions

The South Pass 49 Transfer

On June 3, 2014, Energy XXI GOM, LLC, transferred an asset package to us consisting of certain shallow-water GoM shelf oil and natural gas interests in our South Pass 49 field (the “SP49 Interests”) for $230.0 million to reflect an economic effective date of June 1, 2014 (the “SP49 Transfer”). Prior to the SP49 Transfer, we owned a 43.5% working interest in certain of these assets, and Energy XXI owned a 56.5% working interest in certain of these assets as well as 100% interest in additional assets in the field. As a result of the SP49 Transfer, we have become the sole working interest owner of the South Pass 49 field. We financed the SP49 Transfer with borrowings of approximately $135 million under our prior credit facility and a $95 million capital contribution from EGC.

The following table summarizes the assets acquired and liabilities assumed in the transfer.


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

The Nexen Acquisition

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”).

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 $5.7 million to reflect an economic effective date of September 1, 2013.


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

The West Delta 29 Acquisition

On September 26, 2013, we acquired from W&T Offshore, Inc. (“W&T”) an asset package consisting of certain GoM shelf oil and natural gas interests in the West Delta 29 field (the “WD29 Interests”) for $21.8 million in cash, subject to customary adjustments to reflect an economic effective date of January 1, 2013 (the “WD29 Acquisition”). The WD29 Acquisition was funded with a portion of the proceeds from the sale of certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay Marchand field in a tax-deferred exchange of properties.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(2) Acquisitions – (continued)

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

We have accounted for the Nexen Acquisition and WD29 Acquisition using the acquisition method of accounting for business combinations, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of their respective acquisition dates. In the estimation of fair value, management uses various valuation methods including (i) 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 of Operations and Pro Forma Information

Revenues and lease operating expenses attributable to acquired interests and properties were as follows:


	SUCCESSOR COMPANY				PREDECESSOR COMPANY
(In thousands)	Three Months Ended March 31, 2015		Nine Months Ended March 31, 2015		Three Months Ended March 31, 2014		Nine Months Ended March 31, 2014
SP49 Interests:
Revenues	$	8,311	$	35,342	$	—	$	—
Lease operating expenses	$	837	$	5,200	$	—	$	—
EI Interests:
Revenues	$	4,711	$	24,703	$	8,380	$	8,380
Lease operating expenses	$	6,030	$	16,026	$	3,656	$	3,656
WD29 Interests:
Revenues	$	1,683	$	8,428	$	3,232	$	6,243
Lease operating expenses	$	238	$	609	$	59	$	103

We have 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.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(2) Acquisitions – (continued)

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:

Exclude $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.

Increase DD&A expense by $25.0 million and $82.6 million, respectively, to correspond with the full cost method of accounting.

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 (the “8.25% Senior Notes”).


	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

(3) Pushdown Accounting and Goodwill

As described in Note 1, the Merger resulted in EPL becoming an indirect, wholly-owned subsidiary of Energy XXI. Therefore, we applied “pushdown” accounting, based on guidance from the SEC. In accordance with the acquisition method of accounting, the purchase price established in the Merger was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to, quoted market prices, where available; expected future cash flows based on estimated reserve quantities; estimated costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates; and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the Merger is not deductible for income tax purposes.

On April 2, 2013, we sold certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of production in the months of January 2013 and February 2013 totaling to approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed by Energy XXI in the Merger and a

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(3) Pushdown Accounting and Goodwill – (continued)

corresponding increase 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.

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

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

At September 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital used to estimate fair value, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there was no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at September 30, 2014.

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

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

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

The following 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.


	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	)

The following 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.


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

(5) Property and Equipment

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.

The ceiling test 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.

TABLE OF CONTENTS

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 5^th, April 5^th, July 5^th, and October 5^th, 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 15^th and August 15^th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. 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

Sub Floor

Floor

Ceiling

April 2015 – December 2015

Three-Way Collars

ARGUS-LLS

1,925

32.86

45.00

75.71

Gas Contracts

Remaining Contract Term

Type of Contract

Index

Volume
(MMBtu)

Swap Fixed
Price
($/Mmbtu)

April 2015 – December 2015

Fixed Price Swaps

NYMEX-HH

1,183

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.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(8) Derivative Financial Instruments – (continued)

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


	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	Three Months Ended March 31, 2015			Nine Months Ended March 31, 2015			Three Months Ended March 31, 2014			Nine Months Ended March 31, 2014
Location of (Gain) Loss in Statement of Operations
Cash Settlements
Oil sales	$	(1,170	)	$	(25,578	)	$	—		$	—
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 31, 2015, we had no deposits for collateral with our counterparties.

(9) Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820, “Fair Value Measurements and Disclosures,” establishes a fair value hierarchy with three levels based on the reliability of the inputs used to determine fair value. These levels include: Level 1, defined as inputs such as unadjusted quoted prices in active markets for identical assets and liabilities; Level 2, defined as inputs other than quoted prices in active markets that are either directly or indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market data exists, therefore requiring an entity to develop its own assumptions.

As of March 31, 2015 and June 30, 2014, we held certain financial assets and 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

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(9) Fair Value Measurements – (continued)

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.

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


	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

The carrying values reported 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.

The following table sets forth the carrying values and estimated fair values of our long-term indebtedness.


	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

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(9) Fair Value Measurements – (continued)

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

As addressed in Note 2, “Acquisitions,” we apply fair value concepts in estimating and allocating the fair value of assets acquired and liabilities assumed in acquisitions in accordance with acquisition accounting for business combinations. The inputs to the estimated fair values of assets acquired and liabilities assumed are described in Note 2.

(10) Income Taxes

We are a (U.S.) Delaware company and, as a result of the Merger, a direct subsidiary of EGC. We are a member of a consolidated group of corporations for U.S. federal income tax purposes where Energy XXI, Inc., (the “U.S. Parent”) is the parent entity. Energy XXI indirectly owns 100% of U.S. Parent, but is not a member of the U.S. consolidated group. We operate through our various subsidiaries in the United States as they apply to our current ownership structure. ASC Topic 740 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.

In each interim period, we estimate the annual effective tax rate we expect to be applicable for the current fiscal year and apply it to interim periods. However, during the first quarter of fiscal year 2015, we recorded a goodwill impairment charge of $329 million (see Note 3 — Pushdown Accounting and Goodwill). 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 properties) over their tax bases; however, with continued weakness in commodity pricing, this judgment could change as early as the fourth quarter of fiscal 2015.

On June 3, 2014, we entered an intercompany services and cost allocation agreement with Energy XXI Services, LLC (“Energy Services”), an affiliate of the Company. Services provided by Energy Services include management, legal, accounting, tax, corporate secretarial, human resources, employee benefit administration, office space and other furniture and equipment management, and other support services. Cost of these services for the three months ended March 31, 2015 was approximately $14.0 million, of which approximately $10.4 million is included in general and administrative expense. Cost of these services for the nine months ended March 31, 2015 was approximately $23.8 million, of which approximately $19.5 million is included in general and administrative expense.

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

On March 12, 2015, in connection with EGC’s issuance of the 11.0% Notes, we entered into the Promissory Note with a face value of $325 million. The Promissory Note bears interest at an annual rate of 10%, has a maturity date of October 9, 2018, and is secured by a second priority lien on certain of our assets that secure the obligations under the First Lien Credit Agreement. Interest expense on the Promissory Note amounted to approximately $1.6 million for the three months ended March 31, 2015. See Note 7, “Indebtedness” for more information regarding the Promissory Note.

(12) Commitments and Contingencies

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.

In March 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”).

Plaintiffs alleged a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL, which provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) our directors allegedly breached fiduciary duties in connection with the Merger and (b) 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 January 16, 2015, Plaintiffs filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.

Other. We maintain restricted escrow funds in a trust for future abandonment costs at our East Bay property. The trust was originally funded with $15.0 million and, with accumulated interest, increased to $16.7 million at December 31, 2008. We may draw from the trust upon completion of qualifying abandonment activities at our East Bay field. At March 31, 2015, we had $6.0 million remaining in restricted escrow funds for decommissioning work in our East Bay field, which will remain restricted until substantially all required decommissioning in the East Bay field is complete. Amounts on deposit in the trust account are reflected in Restricted cash on our condensed consolidated balance sheets.

We record liabilities when we deliver production that is in excess of our interest in certain properties. In addition to these imbalances, we may, from time to time, be allocated cash sales proceeds in excess of amounts that we estimate are due to us for our interest in production. These allocations may be subject to further review, may require more information to resolve or may be in dispute.

We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments, increases or decreases, to our net costs or revenues and the related cash flows. Such

TABLE OF CONTENTS

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

(12) Commitments and Contingencies – (continued)

adjustments may be material. 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.

Subsequent Event. In April 2015, we received letters from the Bureau of Ocean Energy Management (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 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.

(13) Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 7, “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 defeasance or covenant defeasance or to discharge the indenture have been satisfied, or when the Guarantor Subsidiary is sold or sells all of its assets. The following supplemental financial information sets forth, on a consolidating basis, the balance sheets, statements of operations and cash flow information for EPL (Parent Company Only) and for the Guarantor Subsidiaries. We have not presented separate financial statements and other disclosures concerning the Guarantor Subsidiaries, or for any individual Guarantor Subsidiary, because management has determined that such information is not material to investors.

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

TABLE OF CONTENTS

SUCCESSOR COMPANY

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


	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

TABLE OF CONTENTS

SUCCESSOR COMPANY

Supplemental Condensed Consolidating Balance Sheet
As of June 30, 2014
(AUDITED)


	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

TABLE OF CONTENTS

SUCCESSOR COMPANY

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


	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	)

TABLE OF CONTENTS

SUCCESSOR COMPANY

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


	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	)

TABLE OF CONTENTS

PREDECESSOR COMPANY

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


	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

TABLE OF CONTENTS

PREDECESSOR COMPANY

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


	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	)

TABLE OF CONTENTS

SUCCESSOR COMPANY

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


	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

TABLE OF CONTENTS

PREDECESSOR COMPANY

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


	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

TABLE OF CONTENTS

Item 2.

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

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

OVERVIEW

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

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

The Merger resulted in EPL becoming an indirect, wholly-owned subsidiary of Energy XXI. Therefore, in the preparation of our financial statements, we have applied “pushdown” accounting, based on guidance from the Securities and Exchange Commission (“SEC”). Pushdown accounting refers to the use of the acquiring entity’s basis of accounting in the preparation of the acquired entity’s financial statements. As a result, our separate financial statements reflect the new basis of accounting recorded by Energy XXI upon acquisition. As such, in accordance with 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.

Energy XXI follows the “full cost” method of accounting for its oil and gas producing activities, while we had historically followed the “successful efforts” method of accounting. Subsequent to the Merger, we converted our 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 generally 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 prior periods and we have applied the full cost method of accounting on a prospective basis from the date of the Merger.

Under the full cost method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other

TABLE OF CONTENTS

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

Under the full cost method, oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.

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.

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

Overview and Outlook

As a result of pushdown accounting in connection with the Merger, the Predecessor Company’s operations are deemed to have ceased on June 3, 2014 and the Successor Company began operations as of that date. In the following discussion, the consolidated financial information for the three and nine months ending March 31, 2015 (reflecting operations of the Successor Company) is not comparable to that for the three and nine months ending March 31, 2014 (reflecting operations of the Predecessor Company). However, the comparability of certain components of our operating results and key operating 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. 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.

As a result of the Merger, the future strategy of EPL is determined by Energy XXI’s Board of Directors. Our fiscal year 2015 capital budget is approximately $250 million, excluding potential capitalized general and administrative expenses. For the nine months ended March 31, 2015, our capital expenditures totaled approximately $228 million, of which approximately $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.

Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as oil and natural gas prices, tropical weather, economic, political and regulatory developments and availability of other sources of energy. Prices for oil and natural gas historically have been extremely volatile and are expected to continue to be volatile. 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 posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, 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

TABLE OF CONTENTS

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. 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 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. During the three and nine months ended March 31, 2015, we recognized ceiling test write-downs 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 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 SEC pricing methodology. Additionally, if the current low commodity price environment or downward trend in 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.

In addition, in April 2015, we received letters from the Bureau of Ocean Energy Management (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 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 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. 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.

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.

We intend to continue to focus on integrating operations to realize consolidation benefits and maximize returns on existing assets by deploying capital resources on lower risk development drilling in the fields where we have previously enjoyed success, and reducing capital commitments on exploration and other activities that do not provide incremental production, while we seek to improve cash flow and pay down debt. We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods. Jack-up rig rates, for example, have fallen by 35 – 50% in recent months and other service providers are similarly cutting their rates.

Known Trends and Uncertainties

Ceiling Test Write-down. During the three and nine months ended March 31, 2015, we recognized write-downs of our oil and natural gas properties. 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.

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

TABLE OF CONTENTS

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

RESULTS OF OPERATIONS

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


	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

(1)

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.

TABLE OF CONTENTS

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

Overview

Our operating results for the three months ended March 31, 2015, compared to the three months ended March 31, 2014, reflect a 7% increase in oil production and a 78% increase in natural gas production. Our product mix for the three months ended March 31, 2015 was 68% oil (including natural gas liquids) compared to 78% for the three months ended March 31, 2014.

Revenue


	Three Months Ended March 31, 2015		Three Months Ended March 31, 2014		$ Change			% Change
	(in thousands)		(in thousands)
Oil and natural gas revenues	$	87,253	$	158,470	$	(71,217	)		-45	%

For 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.

Our overall average selling prices decreased by 55% for the three months ended March 31, 2015 when compared to the three months ended March 31, 2014. Commodity prices are one of the key drivers of earnings generation and net operating cash flow. Average crude oil prices, including a $0.75 realized gain per barrel related to hedging activities, decreased $52.16 per barrel in the third quarter of fiscal 2015, resulting in lower revenues of approximately $76.3 million. Average natural gas prices, including a $0.15 realized gain per Mcf related to hedging activities, decreased $2.28 per Mcf in the third quarter of fiscal 2015, resulting in lower revenues of approximately $1.1 million. 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 flow from operating activities, potentially causing us to reduce spending on our capital program. Reductions in our capital expenditures could result in a reduction of production volumes.

Operating Expenses

Our operating expenses primarily consist of the following:


	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	%

NM — Not meaningful.

(1)

Exploration expenditures and dry hole costs, and DD&A, including accretion expense, are not comparable for the periods presented due to the conversion from successful efforts accounting to full cost accounting effective June 4, 2014.

TABLE OF CONTENTS

LOE increased for the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, primarily due to the acquisition of the EI Interests and SP 49 Interests.

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 31, 2015, we recognized a ceiling test impairment of our oil and natural gas properties totaling $430.9 million.

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.

G&A expenses 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.

For the three months ended March 31, 2014, other operating expenses included a gain on abandonment activities of $0.9 million.

Other Income and Expense

Interest expense decreased approximately $0.7 million for the three months ended March 31, 2015, as compared to the three 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%, reflecting the impact of the fair value adjustment to the carrying amount of the 8.25% Senior Notes recorded in pushdown accounting. 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.

Other income (expense) in the three months ended March 31, 2014 includes a net loss on derivative instruments of $13.1 million consisting of a gain of $3.7 million due to the change in fair value of derivative instruments which were to be settled in the future offset by a loss of $16.9 million on derivative instruments settled during the quarter, primarily from the impact of higher oil prices during 2014. Prior to the Merger, we did not elect to designate derivative instruments as hedges.

Income Taxes

The income tax benefit for the three months ended March 31, 2015 is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. This effective rate excludes the effect of the goodwill impairment charge recorded in the first quarter of fiscal 2015 which is treated as a discrete item for purposes of computing our interim provision (benefit) for income taxes. The effective income tax/(benefit) rate for the three months ended March 31, 2015 was (38.0)% as compared to 36.4% for the three months ended March 31, 2014. The increase in the tax rate is primarily due to an increase in common permanent difference items. See Note 10, “Income Taxes” in the condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report.

TABLE OF CONTENTS

Nine Months Ended March 31, 2015 Compared to Nine Months Ended March 31, 2014

Overview

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.

Revenue


	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	%

For the nine months ended March 31, 2015, our oil and natural gas revenues decreased 14% as compared to the nine months ended March 31, 2014, due primarily to an 11% increase in oil production partially offset by a 24% decrease in average selling prices for our oil. Additionally, we had a 40% increase in natural gas production and partially offset by a 17% decrease in average selling prices for natural gas in the nine months ended March 31, 2015, as compared to the nine months ended March 31, 2014. Revenues for the nine months ended March 31, 2015 include $26.9 million from the impact of hedge accounting.

Our overall average selling prices decreased by 26% for the nine months ended March 31, 2015 when compared to the nine months ended March 31, 2014. Average crude oil prices, including a $5.19 realized gain per barrel related to hedging activities, decreased $24.10 per barrel in the first nine months of fiscal 2015, resulting in lower revenues of approximately $107.5 million. Average natural gas prices, including a $0.12 realized gain per Mcf related to hedging activities, decreased $0.72 per Mcf in the first nine months of fiscal 2015, resulting in lower revenues of approximately $6.0 million.

Operating Expenses

Our operating expenses primarily consist of the following:


	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	%

NM — Not meaningful.

(1)

LOE increased 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 SP 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.

TABLE OF CONTENTS

During the nine months ended March 31, 2015, we recorded a 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 goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since June 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital used to estimate fair value, both of which adversely impacted the fair value of our reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at September 30, 2014.

As a result of our ceiling tests at December 31, 2014 and March 31, 2015, we recognized a ceiling test impairment of our oil and natural gas properties totaling $1.1 billion during the nine months ended March 31, 2015.

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.

G&A expenses 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.

For the nine months ended March 31, 2014, other operating expenses included a loss on abandonment activities of $21.0 million and amortization expense related to our weather derivative of $6.6 million. For the nine months ended March 31, 2014, our loss on abandonment activities primarily reflected an increase of $21.8 million in our 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 interpretations and enforcement by the Bureau of Safety and Environmental Enforcement (“BSEE”) in the deepwater that increased the required scope of work.

Other Income and Expense

Interest expense decreased approximately $5.1 million for the nine months ended March 31, 2015, as compared 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%, reflecting the impact of the fair value adjustment to the carrying amount of the 8.25% Senior Notes recorded in pushdown accounting. 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.

Other income (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.

Income Taxes

The income tax benefit for the nine months ended March 31, 2015 is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. This effective rate excludes the effect of the goodwill impairment charge recorded in the first quarter of fiscal 2015 which is treated as a discrete item for purposes of computing our interim provision (benefit) for income taxes. The effective income tax/(benefit) rate (excluding the discrete item from pre-tax book loss) for the nine months ended March 31, 2015 was (36.6)% as compared to 101.3% for the nine months ended March 31, 2014. The variance in the tax rate is primarily due to changes in common permanent difference items. See Note 10, “Income Taxes” in the condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report.

TABLE OF CONTENTS

LIQUIDITY AND CAPITAL RESOURCES

Overview

As of March 31, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are party with EGC. Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. Future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. Prices for oil and natural gas began to decline significantly during the fourth quarter of calendar 2014 and have continued to be volatile into calendar 2015. These declines in commodity prices have negatively impacted revenues, earnings and cash flows and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.

Our Indebtedness and Available Credit

During March 2015, the Tenth Amendment to the First Lien Credit Agreement dated as of March 3, 2015 (the “Tenth Amendment”) became effective. Pursuant to the terms of the Tenth Amendment, the lenders under the First Lien Credit Agreement reduced the borrowing base for EGC from $1,500 to $500 million, of which such amount $150 million is the borrowing base for EPL (the “Revolving Credit Sub-Facility”). The maturity date of the First Lien Credit Agreement remains April 9, 2018, if certain conditions are met. Additionally, we entered 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 a like amount of the outstanding 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 more information on our Revolving Credit Sub-Facility and the Promissory Note, see Note 7, “Indebtedness” in the condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report.

The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. 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 EPL Notes are no longer outstanding and certain other conditions are met, EGC will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 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. As of March 31, 2015, we were in compliance with all of the covenants under our First Lien Credit Agreement. As a result of the Tenth Amendment, we expect to remain in compliance with the financial covenants thereunder for the foreseeable future.

As 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.

At March 31, 2015, we had $510.0 million in aggregate principal amount outstanding of our 8.25% Senior Notes due February 15, 2018. For more information on our 8.25% Senior Notes, see Note 7, “Indebtedness” in this Quarterly Report and Note 8, “Indebtedness,” of our 2014 Transition Report.

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

TABLE OF CONTENTS

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.

Energy XXI and its subsidiaries are focused on reducing leverage and are pursuing arrangements with third parties to monetize certain midstream assets. Additionally, we may decide to divest of certain non-core assets from time to time. There can be no assurance any of these discussions or transactions will prove successful.

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 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 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 the BOEM letters on our future consolidated financial position, results of operations and cash flow. We intend to continue to work with the BOEM staff to resolve this matter, and we have already undertaken a number of initiatives to mitigate our potential liability resulting from the waiver disqualification and to limit the amount of required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date as well as counting our existing bonds with third parties and certain letters of credit against the BOEM bonding request. The costs of satisfying these supplemental bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, 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.

Capital Expenditures

For fiscal 2015, our capital expenditures are now estimated at $250 million. For the nine months ended March 31, 2015, our capital expenditures totaled approximately $228 million, of which approximately $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,

TABLE OF CONTENTS

costs of drilling and completion operations, drilling results and changes in the borrowing base under the First Lien Credit Agreement and available funding from EGC.

Analysis of Cash Flows

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


	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

The decrease 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.

Net cash used in investing activities decreased for the nine months ended March 31, 2015, as compared to the nine months ended March 31, 2014, primarily due to a reduction in cash used for acquisitions, partially offset by a slight increase in capital expenditures.

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.

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

New Accounting Pronouncements

For information regarding new accounting pronouncements, see the information in Note 1, “Organization and Basis of Presentation — Recent Accounting Pronouncements,” in the condensed consolidated financial 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 Transition 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 a party at March 31, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

TABLE OF CONTENTS

Credit Risk

We monitor our risk of loss due to non-performance by counterparties of their contractual obligations. Our principal exposure to credit risk is through the sale of our oil and natural gas production, which we market to energy marketing companies and refineries and to a lesser extent our derivative counterparties. We monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s creditworthiness. Although we have not generally required our counterparties to provide collateral to support their obligation to us, we may, if circumstances dictate, require collateral in the future. In this manner, we reduce credit risk.

Commodity Price Risk

Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which are volatile and may fluctuate widely. Oil and natural gas price declines such as the recent declines adversely affect our revenues, cash flows and profitability.

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 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.

We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We also use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Any gains or losses resulting from the change in fair value from hedging transactions that are determined to be ineffective are recorded in income, whereas gains and losses from the settlement of hedging contracts are recorded in crude oil and natural gas revenues.

With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.

At March 31, 2015, our crude oil contracts outstanding had an asset position of $1.3 million. A 10% increase in crude oil prices would reduce the fair value by approximately $2.9 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $2.4 million. At March 31, 2015, our natural gas contract outstanding was in an asset position of $1.6 million. A 10% increase in natural gas prices

TABLE OF CONTENTS

would reduce the fair value by approximately $0.3 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.3 million. These fair value changes assume volatility based on prevailing market parameters at March 31, 2015. For a complete discussion of our derivative financial instruments, see Note 8, “Derivative Financial Instruments” of the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

Our ultimate realized gain 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.

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our Revolving Credit Sub-Facility. As of March 31, 2015, total debt included $150.0 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 15% of our total debt outstanding as of March 31, 2015. A 10 percent change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $6,750. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.

Item 4.

CONTROLS AND PROCEDURES.

(a) Quarterly Evaluation of Disclosure Controls and Procedures

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.

Because of 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.

(b) Changes in Internal Control Over Financial Reporting

Effective January 1, 2015, all of EPL’s controls including controls related to information technology and accounting systems were transitioned to Energy XXI’s internal control environment.

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.

TABLE OF CONTENTS

PART II — OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS.

For information regarding legal proceedings, see the information in Note 12, “Commitments and Contingencies” in the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report, which is incorporated by reference into Part II, Item 1 of this Quarterly Report.

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 Transition Report. There have been no material changes in the risk factors set forth in our 2014 Transition Report other than those set forth below.

Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.

Oil 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:

•

domestic and foreign supplies of oil and natural gas;

•

price and quantity of foreign imports of oil and natural gas;

•

actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

•

level of consumer product demand, including as a result of competition from alternative energy sources;

•

level of global oil and natural gas exploration and production activity;

•

domestic and foreign governmental regulations;

•

level of global oil and natural gas inventories;

•

political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;

•

weather conditions;

•

technological advances affecting oil and natural gas production and consumption;

•

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

TABLE OF CONTENTS

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.

TABLE OF CONTENTS

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.

TABLE OF CONTENTS

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 15, 2015

By:

/s/ Rick D. Fox

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

TABLE OF CONTENTS

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
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
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

TABLE OF CONTENTS

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

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

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.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

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

Form 10-Q

EPL Oil & Gas, Inc.

(713) 351-3000

TABLE OF CONTENTS

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 COMPREHENSIVE LOSS (UNAUDITED) (In thousands)

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

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

(1) Organization and Basis of Presentation

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

(1) Organization and Basis of Presentation – (continued)

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

(2) Acquisitions

The South Pass 49 Transfer

The Nexen Acquisition

The West Delta 29 Acquisition

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

(2) Acquisitions – (continued)

Results of Operations and Pro Forma Information

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

(2) Acquisitions – (continued)

(3) Pushdown Accounting and Goodwill

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

(3) Pushdown Accounting and Goodwill – (continued)

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

(4) Earnings Per Share

(5) Property and Equipment

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)

(8) Derivative Financial Instruments – (continued)

(9) Fair Value Measurements

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

(9) Fair Value Measurements – (continued)

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

(9) Fair Value Measurements – (continued)

(10) Income Taxes

(11) Related Party Transactions

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

(11) Related Party Transactions – (continued)

(12) Commitments and Contingencies

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

(12) Commitments and Contingencies – (continued)

(13) Supplemental Condensed Consolidating Financial Information

SUCCESSOR COMPANY Supplemental Condensed Consolidating Balance Sheet As of March 31, 2015 (UNAUDITED)

SUCCESSOR COMPANY Supplemental Condensed Consolidating Balance Sheet As of June 30, 2014 (AUDITED)

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

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

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

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

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

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

OVERVIEW

Overview and Outlook

Known Trends and Uncertainties

RESULTS OF OPERATIONS

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

Overview

Revenue

Operating Expenses

Other Income and Expense

Income Taxes

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

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 COMPREHENSIVE LOSS
(UNAUDITED)
(In thousands)

EPL OIL & GAS, INC. AND SUBSIDIARIES

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

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

EPL OIL & GAS, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

SUCCESSOR COMPANY

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

SUCCESSOR COMPANY

Supplemental Condensed Consolidating Balance Sheet
As of June 30, 2014
(AUDITED)

SUCCESSOR COMPANY

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

SUCCESSOR COMPANY

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

PREDECESSOR COMPANY

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

PREDECESSOR COMPANY

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

SUCCESSOR COMPANY

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

PREDECESSOR COMPANY

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

EPL OIL & GAS, INC. 10-Q