Epl Oil & Gas 10-Q 2015 Q2 Quarterly report

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

 

Form 10-Q

 

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

For the quarterly period ended December 31, 2014
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.Yesx Noo

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).Yesx Noo

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 filero	Accelerated filero
Non-accelerated filerx (Do not check if a smaller reporting company)	Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yeso Nox

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.Yesx Noo

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 December 31, 2014 (Unaudited) and June 30, 2014		1
Condensed Consolidated Statements of Operations (Unaudited) for the three and six months ended December 31, 2014 and 2013		2
Condensed Consolidated Statements of Comprehensive Loss (Unaudited) for the three and six months ended December 31, 2014		3
Condensed Consolidated Statements of Cash Flows (Unaudited) for the six months ended December 31, 2014 and 2013		4
Notes to Condensed Consolidated Financial Statements (Unaudited)		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures about Market Risk		38
Item 4. Controls and Procedures		39
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		41
Item 1A. Risk Factors		41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		43
Item 3. Defaults Upon Senior Securities		43
Item 4. Mine Safety Disclosures		43
Item 5. Other Information		43
Item 6. Exhibits		43

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our 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;

• declines in the prices we receive for our oil and gas production;

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

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

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

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

• uncertainties in estimating 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.

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.

ii

PART I — FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS.

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

	December 31, 2014			June 30, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	484		$	5,601
Trade accounts receivable – net		68,917			72,301
Derivative financial instruments		2,004			—
Deferred tax asset		15,748			24,587
Prepaid expenses		10,060			26,521
Total current assets		97,213			129,010
Property and equipment, under the full cost method of accounting, including $498.7 million and $908.5 million of unevaluated properties not being amortized at December 31, 2014 and June 30, 2014, respectively		2,554,922			3,205,187
Goodwill		—			329,293
Restricted cash		6,024			6,023
Other assets		16			317
Total assets	$	2,658,175		$	3,669,830
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	25,326		$	92,981
Due to EGC		138,057			4,960
Accrued liabilities		133,026			161,518
Asset retirement obligations		39,831			39,831
Derivative financial instruments		—			26,440
Total current liabilities		336,240			325,730
Long-term debt		1,020,462			1,025,566
Asset retirement obligations		218,317			232,864
Deferred tax liabilities		240,049			483,798
Derivative financial instruments		—			2,140
Other		6			6
Total liabilities		1,815,074			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 December 31, 2014 and June 30, 2014		—			—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; 1,000 shares issued and outstanding at December 31, 2014 and June 30, 2014		—			—
Additional paid-in capital		1,599,341			1,599,341
Accumulated other comprehensive income (loss)		5,972			(6,252	)
Retained earnings (loss)		(762,212	)		6,637
Total stockholder's equity		843,101			1,599,726
Total liabilities and stockholder's equity	$	2,658,175		$	3,669,830

 
 
See accompanying notes to condensed consolidated financial statements.

1

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 December 31, 2014			Six Months Ended December 31, 2014			Three Months Ended December 31, 2013			Six Months Ended December 31, 2013
Revenue:
Oil and natural gas	$	156,070		$	329,790		$	141,645		$	324,759
Other		543			932			965			1,843
Total revenue		156,613			330,722			142,610			326,602
Costs and expenses:
Lease operating		55,304			111,604			39,178			81,469
Transportation		1,149			1,774			1,251			2,225
Exploration expenditures and dry hole costs		—			—			12,946			18,092
Impairment of oil and natural gas properties		682,868			682,868			754			766
Goodwill impairment		—			329,293			—			—
Depreciation, depletion and amortization		88,547			162,292			46,512			100,501
Accretion of liability for asset retirement obligations		6,098			12,279			9,835			16,101
General and administrative		6,810			14,852			7,210			13,636
Taxes, other than on earnings		1,944			4,472			2,606			5,891
Gain on sales of assets		—			—			(80	)		(1,825	)
Other		—			21			1,865			28,399
Total costs and expenses		842,720			1,319,455			122,077			265,255
Income (loss) from operations		(686,107	)		(988,733	)		20,533			61,347
Other income (expense):
Interest income		4			4			8			72
Interest expense		(10,947	)		(21,848	)		(12,998	)		(26,175	)
Loss on derivative instruments		(26	)		(56	)		(25,328	)		(55,340	)
Total other expense		(10,969	)		(21,900	)		(38,318	)		(81,443	)
Loss before income taxes		(697,076	)		(1,010,633	)		(17,785	)		(20,096	)
Deferred income tax benefit		(247,598	)		(241,784	)		(5,727	)		(6,754	)
Net loss		(449,478	)		(768,849	)		(12,058	)		(13,342	)
Basic loss per share								(0.31	)		(0.35	)
Diluted loss per share								(0.31	)		(0.35	)
Weighted average common shares used in computing loss per share:
Basic								38,641			38,615
Diluted								38,641			38,615

 
 
See accompanying notes to condensed consolidated financial statements.

2

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

	Three Months Ended December 31, 2014			Six Months Ended December 31, 2014
Net loss	$	(449,478	)	$	(768,849	)
Other comprehensive income (loss)
Crude oil and natural gas cash flow hedges
Unrealized change in fair value net of ineffective portion		22,287			44,174
Effective portion reclassified to earnings during the period		(23,237	)		(25,076	)
Total other comprehensive income (loss)		(950	)		19,098
Deferred income tax expense (benefit)		(143	)		6,874
Net other comprehensive income (loss)		(807	)		12,224
Comprehensive loss	$	(450,285	)	$	(756,625	)

 
 
See accompanying notes to condensed consolidated financial statements.

3

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

	SUCCESSOR COMPANY			PREDECESSOR COMPANY
	Six Months Ended December 31, 2014			Six Months Ended December 31, 2013
Cash flows from operating activities:
Net loss	$	(768,849	)	$	(13,342	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		162,292			100,501
Accretion of liability for asset retirement obligations		12,279			16,101
Change in derivative financial instruments
Proceeds from sale of derivative financial instruments		4,559			—
Other		1			48,184
Non-cash compensation		—			3,896
Deferred income taxes		(241,784	)		(6,604	)
Exploration expenditures		—			1,829
Impairment of oil and natural gas properties		682,868			766
Goodwill impairment		329,293			—
Amortization of premium, discount and deferred financing costs on debt		(5,104	)		2,741
Gain on sales of assets		—			(1,825	)
Other		—			21,815
Changes in operating assets and liabilities:
Trade accounts receivable		9,721			8,344
Prepaid expenses		16,461			7,938
Other assets		301			506
Accounts payable and accrued liabilities		(71,099	)		30,770
Asset retirement obligation settlements		(32,038	)		(26,537	)
Net cash provided by operating activities		98,901			195,083
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		—			51,757
Property acquisitions		(350	)		(25,478	)
Deposit for Nexen Acquisition		—			(7,040	)
Capital expenditures		(239,090	)		(169,936	)
Other property and equipment additions		(58	)		(753	)
Proceeds from sale of assets		—			80
Net cash used in investing activities		(239,498	)		(151,370	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		—			(35,000	)
Advances from EGC		135,480			—
Deferred financing costs		—			(36	)
Purchase of shares into treasury		—			(4,544	)
Exercise of stock options		—			794
Net cash provided by (used in) financing activities		135,480			(38,786	)
Net increase (decrease) in cash and cash equivalents		(5,117	)		4,927
Cash and cash equivalents at beginning of period		5,601			3,885
Cash and cash equivalents at end of period	$	484		$	8,812

 
 
See accompanying notes to condensed consolidated financial statements.

4

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 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

5

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

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

(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 credit facility and a $95 million capital contribution from EGC. See Note 7, “Indebtedness” for more information regarding our credit facility.

6

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

(2) Acquisitions  – (continued)

The following table summarizes the assets acquired and liabilities assumed in the transfer to reflect an economic effective date of June 1, 2014.

(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 March and field in a tax-deferred exchange of properties.

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

7

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

(2) Acquisitions  – (continued)

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 December 31, 2014		Six Months Ended December 31, 2014		Three Months Ended December 31, 2013		Six Months Ended December 31, 2013
SP49 Interests:
Revenues	$	12,051	$	27,031	$	—	$	—
Lease operating expenses	$	2,368	$	4,363	$	—	$	—
EI Interests:
Revenues	$	8,145	$	19,992	$	—	$	—
Lease operating expenses	$	5,731	$	9,996	$	—	$	—
WD29 Interests:
Revenues	$	2,902	$	6,745	$	3,011	$	3,011
Lease operating expenses	$	127	$	371	$	44	$	44

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.

8

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

a. Exclude $13.6 million and $17.0 million, respectively, of our 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.

b. Increase DD&A expense by $39.9 million and $73.2 million, respectively, for our properties to correspond with the full cost method of accounting.

c. Decrease interest expense $3.3 million and $6.6 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of our 8.25% Senior Notes.

	PRO FORMA
(in thousands, except per share data)	Three Months Ended December 31, 2013			Six Months Ended December 31, 2013
Revenue	$	165,603		$	386,270
Net loss		(17,073	)		(19,048	)
Basic loss per share		(0.44	)		(0.49	)
Diluted loss per share		(0.44	)		(0.49	)

(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 March and 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

9

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 would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at 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.

10

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

(4) Earnings Per Share

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 December 31, 2013			Six Months Ended December 31, 2013
	(in thousands, except per share data)
Income (numerator):
Net loss	$	(12,058	)	$	(13,342	)
Net income attributable to participating securities		—			—
Net loss attributable to common shares	$	(12,058	)	$	(13,342	)
Weighted average shares (denominator):
Weighted average shares – basic		38,641			38,615
Dilutive effect of stock options		—			—
Weighted average shares – diluted		38,641			38,615
Basic loss per share	$	(0.31	)	$	(0.35	)
Diluted loss per share	$	(0.31	)	$	(0.35	)

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 December 31, 2013		Six Months Ended December 31, 2013
	(in thousands)
Weighted average shares		987		1,012

(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 proved oil and natural gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. At December 31, 2014, our ceiling test computation resulted in an impairment of our oil and natural gas properties of $682.9 million.

The ceiling test computation takes into account the impact of our cash flow hedges at the end of each financial reporting period. Our ceiling test computation would have resulted in an impairment of our oil and gas properties of $690.3 million had the effects of the cash flow hedges not been considered in the computation.

11

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.

	Six Months Ended December 31, 2014
	(in thousands)
Beginning of period total	$	272,695
Accretion expense		12,279
Liabilities incurred and true-up to liabilities settled		5,212
Liabilities settled		(32,038	)
End of period total		258,148
Less: Current portion		(39,831	)
End of period, noncurrent portion	$	218,317

(7) Indebtedness

The following table sets forth our indebtedness.

	December 31, 2014		June 30, 2014
	(In thousands)
8.25% senior notes due 2018	$	545,462	$	550,566
Revolving Credit Sub-Facility		475,000		475,000
Total indebtedness	$	1,020,462	$	1,025,566

Revolving Credit Sub-Facility

On September 5, 2014, the second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”) underwent its Ninth Amendment (the “Ninth Amendment”). The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, EGC may not permit the following: (a) EGC’s total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, (c) EGC’s current ratio to be less than 1.0 to 1.0 and (d) EGC’s secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in the First Lien Credit Agreement). In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.

Pursuant to the terms of the Ninth Amendment, the lenders under the First Lien Credit Agreement also maintained the borrowing base for EGC at $1.5 billion, of which such amount $475.0 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement (“Revolving Credit Sub-Facility”). These respective borrowing bases were set in accordance with the regular annual process for determination of the borrowing bases and the borrowing bases are to remain effective until the next redetermination thereof under the terms of the First Lien Credit Agreement. For additional information regarding our Revolving Credit Sub-Facility, see Note 8, “Indebtedness,” of our 2014 Transition Report.

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 December 31, 2014, EGC was in

12

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

(7) Indebtedness  – (continued)

compliance with all financial covenants under the First Lien Credit Agreement. Based on projected market conditions and lower commodity prices, we currently expect that EGC will not be in compliance with certain covenants under this agreement in certain future periods. We and EGC are focused on reducing leverage and are pursuing arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of required capital commitments. We and EGC are also evaluating various alternatives with respect to the First Lien Credit Agreement, including other sources of financing, although any such alternative sources of financing likely would be at higher cost than our current Revolving Credit Sub-Facility. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under our Revolving Credit Sub-Facility. Certain payment defaults or an acceleration under our Revolving Credit Sub-Facility could cause a cross-default or cross-acceleration of our 8.25% senior notes due 2018 (the “8.25% Senior Notes”). Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

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.

(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 Gain (loss) on derivative instruments in Other income (expense) in the condensed consolidated statements of operations.

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 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 for information regarding fair values of our derivative instruments.

In connection with the Merger, Energy XXI assumed our existing hedges with contract terms beginning from 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

13

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

(8) Derivative Financial Instruments  – (continued)

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. As of December 31, 2014, we had $7.5 million of monetized amounts remaining in AOCI of which approximately $1.9 million will be recognized in income during the quarters ending March 31, 2015, June 30, 2015, September 30, 2015, and December 31, 2015, respectively.

During 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 December 31, 2014. See Note 13 for information regarding derivative instruments entered subsequent to December 31, 2014.

Gas Contracts

Remaining Contract Term	Type of Contract		Volume (Mmbtu)		Swap Fixed Price ($/Mmbtu)
January 2015 – December 2015		Fixed Price Swaps		1,569,500		4.31

For the three and six months ended December 31, 2014, we reclassified from AOCI a gain of approximately $23.2 million and $25.1 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 $9.5 million ($6.0 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

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

	SUCCESSOR COMPANY						PREDECESSOR COMPANY
	Three Months Ended December 31, 2014			Six Months Ended December 31, 2014			Three Months Ended December 31, 2013		Six Months Ended December 31, 2013
Location of (Gain) Loss in Income Statement
Cash Settlements
Oil sales	$	(22,395	)	$	(24,408	)		—		—
Natural gas sales		(842	)		(668	)		—		—
Total cash settlements		(23,237	)		(25,076	)		—		—
Commodity Derivative Instruments designated as hedging instruments:
Loss on derivative financial instruments
Ineffective portion of commodity derivative instruments		(3	)		—			—		—
Commodity Derivative Instruments not designated as hedging instruments:
Loss on derivative financial instruments
Realized mark to market loss		29			55			3,623		7,156
Unrealized mark to market loss		—			1			21,705		48,184
Total loss on derivative financial instruments		26			56			25,328		55,340
Total (gain) loss	$	(23,211	)	$	(25,020	)	$	25,328	$	55,340

14

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

(8) Derivative Financial Instruments  – (continued)

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 December 31, 2014, 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 December 31, 2014 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 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.

	December 31, 2014		June 30, 2014
	(in thousands)
Assets
Derivative financial instruments designated as hedging instruments
Current	$	2,004		—
Noncurrent		—		—
Total gross derivative financial instruments subject to enforceable netting agreement		2,004		—
Gross amounts offset in balance sheet		—		—
Net amounts presented in balance sheet	$	2,004		—
Liabilities
Derivative financial instruments designated as hedging instruments
Current		—	$	26,440
Noncurrent		—		2,140
Total gross derivative financial instruments subject to enforceable netting agreement		—		28,580
Gross amounts offset in balance sheet		—		—

15

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

(9) Fair Value Measurements  – (continued)

	December 31, 2014		June 30, 2014
	(in thousands)
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.

	December 31, 2014				June 30, 2014
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% Senior Notes	$	545,462	$	416,290	$	550,566	$	545,700
Revolving Credit Sub-Facility		475,000		475,000		475,000		475,000
Total	$	1,020,462	$	891,290	$	1,025,566	$	1,020,700

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.

We estimate our annual effective tax rate 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). In light of the form of the transaction related to the Merger on June 3, 2014, the goodwill recognized as a result of the Merger during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes. Currently, our estimated annual effective tax/(benefit) rate is approximately 35.3% excluding the effect of the goodwill impairment charge. For purposes of computing our interim provision (benefit) for income taxes, the goodwill impairment charge is treated as a discrete item in the quarter in which it occurred. Our actual effective tax/(benefit) rates for the three and six months ended December 31, 2014 were (35.5)% and (23.9)%, respectively. The variance from the U.S. statutory rate of 35% is primarily due to two elements:

16

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

(10) Income Taxes  – (continued)

(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).

(11) Related Party Transactions

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 December 31, 2014 was approximately $5.8 million, of which $5.4 million is included in general and administrative expense. Cost of these services for the six months ended December 31, 2014 was approximately $9.8 million, of which $9.1 million is included in general and administrative expense.

(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 (the “merger agreement”), 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 December 31, 2014, 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

17

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

(12) Commitments and Contingencies  – (continued)

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 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.

(13) Subsequent Events

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.

(14) Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 7, 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.

18

SUCCESSOR COMPANY
 
Supplemental Condensed Consolidating Balance Sheet
As of December 31, 2014
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	484		$	—	$	—		$	484
Trade accounts receivable – net		68,773			144		—			68,917
Intercompany receivables		—			31,805		(31,805	)		—
Derivative financial instruments		2,004			—		—			2,004
Deferred tax asset		15,748			—		—			15,748
Prepaid expenses		10,060			—		—			10,060
Total current assets		97,069			31,949		(31,805	)		97,213
Net property and equipment		2,390,774			164,148		—			2,554,922
Investment in affiliates		128,352			—		(128,352	)		—
Restricted cash		6,024			—		—			6,024
Other assets		418			90		(492	)		16
Total assets	$	2,622,637		$	196,187	$	(160,649	)	$	2,658,175
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Accounts payable	$	24,938		$	388	$	—		$	25,326
Due to EGC		138,057			—		—			138,057
Intercompany payables		31,805			—		(31,805	)		—
Accrued liabilities		133,518			—		(492	)		133,026
Asset retirement obligations		34,627			5,204		—			39,831
Total current liabilities		362,945			5,592		(32,297	)		336,240
Long-term debt		1,020,462			—		—			1,020,462
Asset retirement obligations		177,459			40,858		—			218,317
Deferred tax liabilities		218,664			21,385		—			240,049
Other		6			—		—			6
Total liabilities		1,779,536			67,835		(32,297	)		1,815,074
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		5,972			—		—			5,972
Retained earnings (loss)		(762,212	)		42,873		(42,873	)		(762,212	)
Total stockholder's equity		843,101			128,352		(128,352	)		843,101
Total liabilities and stockholder's equity	$	2,622,637		$	196,187	$	(160,649	)	$	2,658,175

19

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

	Parent Company Only			Guarantor Subsidiaries		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

20

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

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	144,345		$	11,725		$	—	$	156,070
Other		461			82			—		543
Total revenue		144,806			11,807			—		156,613
Costs and expenses:
Lease operating		50,044			5,260			—		55,304
Transportation		1,148			1			—		1,149
Impairment of oil and natural gas properties		682,868			—			—		682,868
Depreciation, depletion and amortization		82,382			6,165			—		88,547
Accretion of liability for asset retirement obligations		4,910			1,188			—		6,098
General and administrative		6,810			—			—		6,810
Taxes, other than on earnings		494			1,450			—		1,944
Total costs and expenses		828,656			14,064			—		842,720
Loss from operations		(683,850	)		(2,257	)		—		(686,107	)
Other income (expense):
Interest income		4			—			—		4
Interest expense		(10,947	)		—			—		(10,947	)
Loss on derivative instruments		(26	)		—			—		(26	)
Income from equity investments		(1,424	)		—			1,424		—
Total other income (expense)		(12,393	)		—			1,424		(10,969	)
Loss before provision for income taxes		(696,243	)		(2,257	)		1,424		(697,076	)
Deferred income tax benefit		(246,765	)		(833	)		—		(247,598	)
Net loss	$	(449,478	)	$	(1,424	)	$	1,424	$	(449,478	)
Comprehensive loss
Net loss		(449,478	)		(1,424	)		1,424		(449,478	)
Other comprehensive loss		(807	)		—			—		(807	)
Comprehensive loss	$	(450,285	)	$	(1,424	)	$	1,424	$	(450,285	)

21

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

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	300,437		$	29,353	$	—		$	329,790
Other		778			154		—			932
Total revenue		301,215			29,507		—			330,722
Costs and expenses:
Lease operating		102,618			8,986		—			111,604
Transportation		1,772			2		—			1,774
Impairment of oil and natural gas properties		682,868			—		—			682,868
Goodwill impairment		329,293			—		—			329,293
Depreciation, depletion and amortization		150,387			11,905		—			162,292
Accretion of liability for asset retirement obligations		10,252			2,027		—			12,279
General and administrative		14,852			—		—			14,852
Taxes, other than on earnings		599			3,873		—			4,472
Other		21			—		—			21
Total costs and expenses		1,292,662			26,793		—			1,319,455
Income (loss) from operations		(991,447	)		2,714		—			(988,733	)
Other income (expense):
Interest income		4			—		—			4
Interest expense		(21,848	)		—		—			(21,848	)
Loss on derivative instruments		(56	)		—		—			(56	)
Income from equity investments		1,711			—		(1,711	)		—
Total other income (expense)		(20,189	)		—		(1,711	)		(21,900	)
Income (loss) before provision for income taxes		(1,011,636	)		2,714		(1,711	)		(1,010,633	)
Deferred income tax expense (benefit)		(242,787	)		1,003		—			(241,784	)
Net income (loss)	$	(768,849	)	$	1,711	$	(1,711	)	$	(768,849	)
Comprehensive income (loss)
Net income (loss)		(768,849	)		1,711		(1,711	)		(768,849	)
Other comprehensive income		12,224			—		—			12,224
Comprehensive income (loss)	$	(756,625	)	$	1,711	$	(1,711	)	$	(756,625	)

22

PREDECESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2013
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	123,256		$	18,389	$	—		$	141,645
Other		152			813		—			965
Total revenue		123,408			19,202		—			142,610
Costs and expenses:
Lease operating		33,405			5,773		—			39,178
Transportation		1,250			1		—			1,251
Exploration expenditures and dry hole costs		12,329			617		—			12,946
Impairment of oil and natural gas properties		754			—		—			754
Depreciation, depletion and amortization		40,617			5,895		—			46,512
Accretion of liability for asset retirement obligations		8,168			1,667		—			9,835
General and administrative		7,210			—		—			7,210
Taxes, other than on earnings		236			2,370		—			2,606
Gain on sale of assets		(80	)		—					(80	)
Other		1,865			—		—			1,865
Total costs and expenses		105,754			16,323		—			122,077
Income from operations		17,654			2,879		—			20,533
Other income (expense):
Interest income		8			—		—			8
Interest expense		(12,998	)		—		—			(12,998	)
Gain on derivative instruments		(25,328	)		—		—			(25,328	)
Income from equity investments		1,819			—		(1,819	)		—
Total other expense		(36,499	)		—		(1,819	)		(38,318	)
Income (loss) before provision for income taxes		(18,845	)		2,879		(1,819	)		(17,785	)
Deferred income tax expense (benefit)		(6,787	)		1,060		—			(5,727	)
Net income (loss)	$	(12,058	)	$	1,819	$	(1,819	)	$	(12,058	)

23

PREDECESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2013
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	283,158		$	41,601	$	—		$	324,759
Other		279			1,564		—			1,843
Total revenue		283,437			43,165		—			326,602
Costs and expenses:
Lease operating		69,400			12,069		—			81,469
Transportation		2,224			1		—			2,225
Exploration expenditures and dry hole costs		17,474			618		—			18,092
Impairment of oil and natural gas properties		766			—		—			766
Depreciation, depletion and amortization		89,068			11,433		—			100,501
Accretion of liability for asset retirement obligations		13,245			2,856		—			16,101
General and administrative		13,636			—		—			13,636
Taxes, other than on earnings		461			5,430		—			5,891
Gain on sale of assets		(1,825	)		—		—			(1,825	)
Other		28,272			127		—			28,399
Total costs and expenses		232,721			32,534		—			265,255
Income from operations		50,716			10,631		—			61,347
Other income (expense):
Interest income		72			—		—			72
Interest expense		(26,175	)		—		—			(26,175	)
Gain on derivative instruments		(55,340	)		—		—			(55,340	)
Income from equity investments		6,749			—		(6,749	)		—
Total other expense		(74,694	)		—		(6,749	)		(81,443	)
Income (loss) before provision for income taxes		(23,978	)		10,631		(6,749	)		(20,096	)
Deferred income tax expense (benefit)		(10,636	)		3,882		—			(6,754	)
Net income (loss)	$	(13,342	)	$	6,749	$	(6,749	)	$	(13,342	)

24

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

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

25

PREDECESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2013
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	173,834		$	21,249		$	—	$	195,083
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		51,757			—			—		51,757
Property acquisitions		(25,478	)		—			—		(25,478	)
Deposit for Nexen Acquisition		(7,040	)		—			—		(7,040	)
Capital expenditures		(148,687	)		(21,249	)		—		(169,936	)
Other property and equipment additions		(753	)		—			—		(753	)
Proceeds from sale of assets		80			—			—		80
Net cash used in investing activities		(130,121	)		(21,249	)		—		(151,370	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		(35,000	)		—			—		(35,000	)
Deferred financing costs		(36	)		—			—		(36	)
Purchase of shares into treasury		(4,544	)		—			—		(4,544	)
Exercise of stock options		794			—			—		794
Net cash used in financing activities		(38,786	)		—			—		(38,786	)
Net increase in cash and cash equivalents		4,927			—			—		4,927
Cash and cash equivalents at beginning of period		3,885			—			—		3,885
Cash and cash equivalents at end of period	$	8,812		$	—		$	—	$	8,812

26

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

27

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 six months ending December 31, 2014 (reflecting operations of the Successor Company) is not comparable to that for the three and six months ending December 31, 2013 (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 the Company 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. 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 December 31, 2014 ranged from a high of $107.26 to a low of $53.27 in the last calendar quarter of the year, a decrease of 50.3%, and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to December 31, 2014 ranged from a high of $6.15 to a low of $2.89, a decrease of 53%. As of January 30, 2015, the spot market

28

price for WTI declined further to $48.24. 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 sustained periods of low prices for oil and natural gas are likely to materially adversely affect 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. At December 31, 2014, we recognized a ceiling test write-down of our oil and natural gas properties totaling $682.9 million. The write-down did not impact our cash flows from operating activities but did reduce net income and stockholder’s equity. If the current downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in calendar 2015 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. The decline in commodity prices, if sustained, may result in a reduction of our borrowing base under our Revolving Credit Sub-Facility, which would adversely affect our working capital available to fund our capital spending program as well as potentially require us to repay certain of our outstanding indebtedness. The next borrowing base redetermination is expected during the quarter ended June 30, 2015, although an earlier redetermination is possible under our Revolving Credit Sub-Facility. In addition, a continued low commodity price environment and the negative impact to our cash flow from operations, when combined with our significant indebtedness, will impair our ability to comply in future quarters with our debt instruments unless we are able to improve our liquidity position or take other mitigating actions. See “Risk Factors” in Part I, Item 1A of our 2014 Transition Report and Item 1A of Part II of this Quarterly Report for a more detailed discussion of these risks.

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, 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. To further accelerate the reduction in leverage, we and EGC are pursuing potential arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of required capital commitments. We and EGC are also evaluating various alternatives with respect to the Revolving Credit Facility and other indebtedness. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility, including our Revolving Credit Sub-Facility, as well as all of the other outstanding indebtedness of EGC and EPL. Certain payment defaults or an acceleration under our Revolving Credit Sub-Facility could cause a cross-default or cross-acceleration of our 8.25% Senior Notes. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

Known Trends and Uncertainties

Ceiling Test Write-down.  During the three months ended December 31, 2014, we recognized a write-down of our oil and natural gas properties. Continued declines or suppression of commodity prices and/or widening negative price differentials could result in additional write-downs of our oil and natural gas properties in future periods.

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 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.

29

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 December 31, 2014			Three Months Ended December 31, 2013			Six Months Ended December 31, 2014			Six Months Ended December 31, 2013
Net production (per day):
Oil (Bbls)		18,465			15,109			18,264			16,295
Natural gas (Mcf)		38,737			29,101			38,735			31,399
Total (Boe)		24,921			19,959			24,720			21,528
Average sales prices(1):
Oil (per Bbl)	$	83.99		$	94.37		$	90.05		$	101.07
Natural gas (per Mcf)		3.76			3.91			3.81			3.76
Total (per Boe)		68.07			77.14			72.50			81.98
Oil and natural gas revenues (in thousands):
Oil	$	142,680		$	131,183		$	302,620		$	303,030
Natural gas		13,390			10,462			27,170			21,729
Total		156,070			141,645			329,790			324,759
Impact of derivatives instruments settled during the period(1):
Oil (per Bbl)				$	(2.65	)				$	(2.40	)
Natural gas (per Mcf)					0.02						0.01
Average costs (per Boe):
LOE	$	24.12		$	21.34		$	24.54		$	20.57
Taxes, other than on earnings		0.85			1.42			0.98			1.49
General and administrative (“G&A”) expenses		2.97			3.93			3.27			3.44
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil	$	(14,420	)				$	(32,542	)
Changes in production volumes of oil		25,917						32,132
Total increase (decrease) in oil sales		11,497						(410	)
Changes in prices of natural gas	$	(401	)				$	289
Changes in production volumes of natural gas		3,329						5,152
Total increase in natural gas sales		2,928						5,441

(1) For the three and six months ended December 31, 2014, 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.

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Three Months Ended December 31, 2014 Compared to Three Months Ended December 31, 2013

Overview

Our operating results for the three months ended December 31, 2014, compared to the three months ended December 31, 2013, reflect a 22% increase in oil production and a 33% increase in natural gas production. Our product mix for the three months ended December 31, 2014 was 74% oil (including natural gas liquids) compared to 76% for the three months ended December 31, 2013.

Revenue

	Three Months Ended December 31, 2014		Three Months Ended December 31, 2013		$ Change		% Change
	(in thousands)		(in thousands)
Oil and natural gas revenues	$	156,070	$	141,645	$	14,425		10	%

For the three months ended December 31, 2014, our oil and natural gas revenues increased 10% as compared to the three months ended December 31, 2013, due primarily to a 22% increase in oil production partially offset by an 11% decrease in average selling prices for our oil. We also experienced an increase in natural gas revenues, primarily due to a 33% increase in natural gas production partially offset by a 4% decrease in average selling prices for natural gas in the three months ended December 31, 2014, as compared to the three months ended December 31, 2013. Revenues for the three months ended December 31, 2014 include $23.2 million from the impact of hedge accounting.

Our overall average selling prices decreased by 12% for the three months ended December 31, 2014 when compared to the three months ended December 31, 2013. Commodity prices are one of the key drivers of earnings generation and net operating cash flow. Average crude oil prices, including a $14.28 realized gain per barrel related to hedging activities, decreased $10.38 per barrel in the second quarter of fiscal 2015, resulting in lower revenues of approximately $14.4 million. Average natural gas prices, including a $0.24 realized gain per Mcf related to hedging activities, decreased $0.15 per Mcf in the second quarter of fiscal 2015, resulting in lower revenues of approximately $0.4 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.

Our overall production volumes increased by 25% for the three months ended December 31, 2014 as compared to the three months ended December 31, 2013, due primarily to an increase in production in our Ship Shoal 208 area and production from the recently acquired EI Interests and SP 49 Interests. Production from the EI Interests and SP 49 Interests increased our production rate by approximately 1,320 Boe per day and 3,387 Boe per day, respectively, for the quarter ended December 31, 2014.

Operating Expenses

Our operating expenses primarily consist of the following:

	Three Months Ended December 31, 2014		Three Months Ended December 31, 2013		$ Change			% Change
	(in thousands)		(in thousands)
LOE	$	55,304	$	39,178	$	16,126			41	%
Exploration expenditures and dry hole costs(1)		—		12,946		NM			NM
Impairment of oil and natural gas properties		682,868		754		NM			NM
DD&A, including accretion expense(1)		94,645		56,347		NM			NM
G&A expenses		6,810		7,210		(400	)		-6%

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	Three Months Ended December 31, 2014		Three Months Ended December 31, 2013		$ Change			% Change
	(in thousands)		(in thousands)
Taxes, other than on earnings		1,944		2,606		(662	)		-25	%
Other		—		1,865		(1,865	)		-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.

LOE increased for the three months ended December 31, 2014, as compared to the three months ended December 31, 2013, 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 December 31, 2014, we recognized a ceiling test impairment of our oil and natural gas properties totaling $682.9 million.

Under successful efforts accounting during the three months ended December 31, 2013, we recorded approximately $9.0 million in seismic expense and $2.2 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.

For the three months ended December 31, 2013, other operating expenses included amortization expense related to our weather derivative of $2.7 million partially offset by a gain on abandonment activities of $0.7 million.

Other Income and Expense

Interest expense decreased approximately $2.1 million for the three months ended December 31, 2014, as compared to the three months ended December 31, 2013 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 December 31, 2013 includes a net loss on derivative instruments of $25.3 million consisting of a loss of $21.7 million due to the change in fair value of derivative instruments which were to be settled in the future and a net loss of $3.6 million on derivative instruments settled during the quarter, primarily from the impact of higher oil prices during 2013. Prior to the Merger, we did not elect to designate derivative instruments as hedges.

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Income Taxes

The income tax benefit for the three months ended December 31, 2014 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. In light of the form of the Merger transaction on June 3, 2014, the goodwill recognized in pushdown accounting during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes. The effective income tax/(benefit) rate (excluding the discrete item from pre-tax book loss) for the three months ended December 31, 2014 was (35.5)% as compared to 32.2% for the three months ended December 31, 2013. The increase in the tax rate is primarily due to two elements: (i) the increase in pre-tax net loss and (ii) 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.

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

Overview

Our operating results for the six months ended December 31, 2014, compared to the six months ended December 31, 2013, reflect a 12% increase in oil production and a 23% increase in natural gas production. Our product mix for the six months ended December 31, 2014 was 74% oil (including natural gas liquids) compared to 76% for the six months ended December 31, 2013.

Revenue

	Six Months Ended December 31, 2014		Six Months Ended December 31, 2013		$ Change		% Change
	(in thousands)		(in thousands)
Oil and natural gas revenues	$	329,790	$	324,759	$	5,031		2	%

For the six months ended December 31, 2014, our oil and natural gas revenues increased 2% as compared to the six months ended December 31, 2013, due primarily to a 12% increase in oil production partially offset by an 11% decrease in average selling prices for our oil. Additionally, we had a 23% increase in natural gas production and a 1% increase in average selling prices for natural gas in the six months ended December 31, 2014, as compared to the six months ended December 31, 2013. Revenues for the six months ended December 31, 2014 include $25.1 million from the impact of hedge accounting.

Our overall average selling prices decreased by 12% for the six months ended December 31, 2014 when compared to the six months ended December 31, 2013. Average crude oil prices, including a $7.86 realized gain per barrel related to hedging activities, decreased $11.02 per barrel in the first six months of fiscal 2015, resulting in lower revenues of approximately $32.5 million. Average natural gas prices, including a $0.09 realized gain per Mcf related to hedging activities, increased $0.05 per Mcf in the first six months of fiscal 2015, resulting in higher revenues of approximately $0.3 million.

Our overall production volumes increased by 15% for the six months ended December 31, 2014 when compared to the six months ended December 31, 2013, due primarily to an increase in production in our Ship Shoal 208 area and production from the recently acquired EI Interests and SP 49 Interests. Production from the EI Interests and SP 49 Interests increased our production rate by approximately 1,369 Boe per day and 3,359 Boe per day, respectively, for the six months ended December 31, 2014.

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Operating Expenses

Our operating expenses primarily consist of the following:

	Six Months Ended December 31, 2014		Six Months Ended December 31, 2013		$ Change			% Change
	(in thousands)		(in thousands)
LOE	$	111,604	$	81,469	$	30,135			37	%
Exploration expenditures and dry hole costs(1)		—		18,092		NM			NM
Impairment of oil and natural gas properties		682,868		766		NM			NM
Goodwill impairment		329,293		—		NM			NM
DD&A, including accretion expense(1)		174,571		116,602		NM			NM
G&A expenses		14,851		13,636		1,215			9	%
Taxes, other than on earnings		4,472		5,891		(1,419	)		-24	%
Other		21		28,399		(28,378	)		-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.

LOE increased for the six months ended December 31, 2014, as compared to the six months ended December 31, 2013, primarily due to the acquisition of the EI Interests and SP 49 Interests. LOE for the six months ended December 31, 2014 also included non-routine costs associated with pipeline maintenance in two fields in addition to other non-routine workover and other expenses.

During the six months ended December 31, 2014, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero 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 test at December 31, 2014, we recognized a ceiling test impairment of our oil and natural gas properties totaling $682.9 million during the six months ended December 31, 2014.

Under successful efforts accounting during the six months ended December 31, 2013, we recorded approximately $11.1 million in seismic expense and $4.7 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.

For the six months ended December 31, 2013, other operating expenses included a loss on abandonment activities of $21.9 million and amortization expense related to our weather derivative of $6.6 million. For the six months ended December 31, 2013, 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 $4.3 million for the six months ended December 31, 2014, as compared to the six months ended December 31, 2013 due primarily to a decrease in our effective interest

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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 six months ended December 31, 2013 includes a net loss on derivative instruments of $55.3 million consisting of a loss of $48.2 million due to the change in fair value of derivative instruments which were to be settled in the future and a net loss of $7.2 million on derivative instruments settled during the quarter primarily from the impact of higher oil prices during 2013. Prior to the Merger, we did not elect to designate derivative instruments as hedges.

Income Taxes

The income tax benefit for the six months ended December 31, 2014 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. In light of the form of the Merger transaction on June 3, 2014, the goodwill recognized in pushdown accounting during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes. The effective income tax/(benefit) rate (excluding the discrete item from pre-tax book loss) for the six months ended December 31, 2014 was (35.5)% as compared to 33.6% for the six months ended December 31, 2013. The increase in the tax rate is primarily due to two elements: (i) the increase in pre-tax net loss and (ii) 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.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. However, future cash flows are subject to a number of variables, 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 decline into the first month of 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

As of December 31, 2014, we had $475 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are party with EGC. On September 5, 2014, the Ninth Amendment to the First Lien Credit Agreement (the “Ninth Amendment”) became effective. Pursuant to the terms of the Ninth Amendment, the lenders maintained the borrowing base for EGC at $1.5 billion, of which $475 million remains the borrowing base for EPL. These respective borrowing bases were set in accordance with the regular annual process for determination of the borrowing bases and the borrowing bases are to remain effective until the next redetermination thereof under the terms of the First Lien Credit Agreement. As of February 9, 2015, we have fully utilized amounts available under our Revolving Credit Sub-Facility. For more information on our Revolving Credit Sub-Facility, see Note 7, “Indebtedness,” in the condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report.

If current commodity prices do not improve prior to the next borrowing base redetermination which is expected during the quarter ended June 30, 2015, although an earlier redetermination is possible, our borrowing base under the Revolving Credit Sub-Facility may be reduced, which would impact the working capital available to fund our capital spending program. If there is a decrease in our borrowing base as a result of the outcome of a borrowing base redetermination and, as a result of such decrease, the outstanding borrowings under our Revolving Credit Sub-Facility exceed the redetermined borrowing base, we will be required to repay such excess. We may not have the financial resources in the future to make any mandatory principal prepayments required under our Revolving Credit Sub-Facility.

As of December 31, 2014, EGC was in compliance with all covenants under the First Lien Credit Agreement. Based on projected market conditions and lower commodity prices, we currently expect that EGC

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will not be in compliance with certain covenants under this agreement in certain future periods. EGC is focused on reducing its leverage and is pursuing arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable further reductions in the amount of required capital commitments. We and EGC are also evaluating various alternatives with respect to the First Lien Credit Agreement, including other sources of financing, although any such alternative sources of financing likely would be at higher cost than the current Revolving Credit Sub-Facility. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the First Lien Credit Agreement would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the First Lien Credit Agreement, including under our Revolving Credit Sub-Facility. Certain payment defaults or an acceleration under our Revolving Credit Sub-Facility could cause a cross-default or cross-acceleration of our 8.25% Senior Notes. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

At December 31, 2014, 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 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 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 December 31, 2015, without additional advances from EGC, further reductions in capital expenditures or sales of non-core assets by us or EGC.

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

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reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. If we are unable to obtain any additional required bonds or assurances, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations.

Capital Expenditures

For fiscal 2015, our capital expenditures are now estimated at $250 million. For the six months ended December 31, 2014, our capital expenditures totaled approximately $215 million, of which approximately $153 million was spent on development of core properties, $36 million on exploration of core properties and $26 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 primarily from existing cash flows from operating activities 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, 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:

	Six Months Ended December 31, 2014			Six Months Ended December 31, 2013
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	98,901		$	195,083
Net cash used in investing activities		(239,498	)		(151,370	)
Net cash provided by (used in) financing activities		135,480			(38,786	)

The decrease in our 2014 cash flows from operating activities primarily reflects decreases in revenues due to the decrease in oil prices and changes in working capital during the six months ended December 31, 2014, as compared to the six months ended December 31, 2013.

Net cash used in investing activities increased for the six months ended December 31, 2014, as compared to the six months ended December 31, 2013, due to an increase in capital expenditures in the six months ended December 31, 2014. In addition, net cash used in investing activities for the six months ended December 31, 2013 is net of the reduction of restricted cash of $51.8 million associated with the sale of interests in the Bay March and field and used to fund the WD29 Acquisition.

Net cash provided by financing activities during the six months ended December 31, 2014 reflects $135.5 million in advances from EGC. Net cash used in financing activities during the six months ended December 31, 2013 reflects $35.0 million of repayments of amounts borrowed 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.

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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 December 31, 2014, 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.

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. If commodity prices do not improve prior to our next borrowing base redetermination, the borrowing base will be reduced, which would require us to repay that portion, if any, of our outstanding indebtedness under the Revolving Credit Sub-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

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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 December 31, 2014, our natural gas contract outstanding was in an asset position of $2.0 million. A 10% increase in natural gas prices would reduce the fair value by approximately $0.5 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.5 million. These fair value changes assume volatility based on prevailing market parameters at December 31, 2014. For a complete discussion of our derivative financial instruments, see Note 8 of the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

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.

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 December 31, 2014, total debt included $475.0 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 48% of our total debt outstanding as of December 31, 2014. A 10 percent change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $22,000. 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 December 31, 2014.

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

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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

Subsequent to our merger with Energy XXI on June 3, 2014, certain of our processes mainly related to treasury functions, asset retirement obligations, depletion, debt, related parties, commitments and contingencies, reserve reporting, unevaluated property, derivative financial instruments, fair value valuations, income taxes and pushdown accounting were conducted within Energy XXI’s internal control environment. Post-merger, these processes were subjected to the controls existing at the Energy XXI level and were evaluated accordingly, as we continue towards aligning our controls with Energy XXI’s existing 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 December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 December 31, 2014 ranged from a high of $107.26 to a low of $53.27 in the last calendar quarter of the year, a decrease of 50.3%, and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to December 31, 2014 ranged from a high of $6.15 to a low of $2.89, a decrease of 53%. As of January 30, 2015, the spot market price for WTI declined further to $48.24. 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

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

The borrowing base under EGC’s Revolving Credit Facility, including our Revolving Credit Sub-Facility, is subject to semi-annual redeterminations and could be reduced in the future if commodity prices decline, which may require us to pay down amounts outstanding in excess of our borrowing base and may limit available funding for exploration and development.

As of December 31, 2014, borrowings under our Revolving Credit Sub-Facility were fully drawn at $475.0 million. The amounts available for borrowing under the Revolving Credit Facility, including our Revolving Credit Sub-Facility, are subject to a borrowing base, which is determined by the lenders taking into account estimated proved reserves and are subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. If oil and natural gas commodity prices do not improve, the borrowing base under the Revolving Credit Sub-Facility will be reduced. If there is a decrease in our borrowing base as a result of the outcome of a borrowing base redetermination and, as a result of such decrease, the outstanding borrowings under our Revolving Credit Sub-Facility exceed the redetermined borrowing base, we will be required to repay such excess. We may not have the financial resources in the future to make any mandatory principal prepayments required under our Revolving Credit Sub-Facility. Additionally, so long as our Revolving Credit-Sub Facility is fully drawn, we will depend on borrowings under EGC’s Revolving Credit Facility for a portion of our future capital needs. If EGC experiences a similar reduction of its borrowing base under the Revolving Credit Facility, we may be unable to obtain adequate funding. 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.

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.

EGC’s Revolving Credit Facility requires EGC, on a consolidated basis, to maintain certain financial covenants along with other covenants including, but not limited to, those limiting its ability to declare and pay dividends or make other payments, its ability to incur debt, restrictions on change of control, and the ability to enter into certain hedging agreements. Similarly, our Revolving Credit Sub-Facility restricts our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. EGC’s cash flow is highly dependent on the prices it receives for oil and natural gas, which have declined significantly in the quarter ended December 31, 2014 and declined further in the current quarter. Based on projected market conditions and commodity prices, we currently expect that EGC will not be in compliance with certain covenants under the Revolving Credit Facility in certain future periods. We and EGC are evaluating various alternatives with respect to the Revolving Credit Facility, but there is no certainty that we and EGC will be able to implement any alternatives or otherwise resolve future covenant compliance requirements. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under our Revolving Credit Sub-Facility.

Any such acceleration under the Revolving Credit Facility, including our Revolving Credit Sub-Facility, could cause a cross-default or cross-acceleration of all of our and EGC’s other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our other outstanding indebtedness. Acceleration of debt of this magnitude likely could result in a reorganization or other restructuring.

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We and EGC may need to obtain bonds or other surety in order to maintain compliance with those regulations promulgated by the U.S. Bureau of Ocean Energy Management, which, if required, could be costly and reduce borrowings available 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. 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 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. Notwithstanding these bonds currently in place, the BOEM has the authority to require OCS operators such as us to obtain and maintain supplemental bonds issued to the agency that serve to further assure compliance with lease obligations, most notably, decommissioning obligations including the permanent plugging of wells and removal of platforms, pipelines and related facilities. While we believe that the BOEM has waived the obligation to provide supplemental bonding based on such demonstrations, the BOEM retains the right to re-evaluate our decommissioning obligations or our market capitalization and asset impairments or otherwise amend the criteria that must be satisfied by an operator to qualify for waiver from supplemental bonding on the basis of financial strength and reliability and, as a result, determine that we no longer qualify for such waiver from the supplemental bonding requirements. For example, in August 2014, the BOEM published an Advance Notice of Proposed Rulemaking, pursuant to which it seeks to bolster its current bonding requirements for offshore oil and gas operations. The costs of satisfying supplemental bonding requirements could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, EGC may be required to provide letters of credit on our behalf to support the issuance of these bonds or other surety. Such a letter of credit would likely be issued under the Revolving Credit Facility, which would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. If we are unable to obtain any additional required bonds or assurances, the BOEM may require any of our operations on federal leases to be suspended or terminated, which would materially and adversely affect our financial condition, cash flows and results of operations

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

None

Item 3. DEFAULTS UPON SENIOR SECURITIES.

None

Item 4. MINE SAFETY DISCLOSURES.

None

Item 5. OTHER INFORMATION.

None

Item 6. EXHIBITS.

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

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SIGNATURES

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

	EPL Oil & Gas, Inc.
Date: February 13, 2015	By: /s/ Rick D. Fox Rick D. Fox Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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INDEX TO EXHIBITS

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

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Exhibit Number	Exhibit Description	Incorporated by Reference Form	SEC File Number	Exhibit	Filing Date	Filed/ Furnished Herewith
101.INS*	XBRL Instance Document					X
101.SCH*	XBRL Taxonomy Extension Schema Document					X
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document					X
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document					X
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document					X
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document					X

* Incorporated herein by reference as indicated.

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