Epl Oil & Gas 10-Q 2015 Q1 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 September 30, 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.)

919 Milam Street, Suite 1600, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 228-0711

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 September 30, 2014 (Unaudited) and June 30, 2014		2
Condensed Consolidated Statements of Operations (Unaudited) for the three months ended September 30, 2014 and 2013		3
Condensed Consolidated Statement of Comprehensive Loss (Unaudited) for the three months ended September 30, 2014		4
Condensed Consolidated Statements of Cash Flows (Unaudited) for the three months ended September 30, 2014 and 2013		5
Notes to Condensed Consolidated Financial Statements (Unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of   Operations		25
Item 3. Quantitative and Qualitative Disclosures about Market Risk		32
Item 4. Controls and Procedures		33
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		35
Item 1A. Risk Factors		35
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		35
Item 3. Defaults Upon Senior Securities		35
Item 4. Mine Safety Disclosures		35
Item 5. Other Information		35
Item 6. Exhibits		35

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;

• our financial position;

• the extent to which we are leveraged;

• our cash flow and liquidity;

• declines in the prices we receive for our oil and gas which would affect our operating results and cash flows;

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

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

• availability of drilling and production equipment and field service providers;

• 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”).

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.

1

PART I — FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS.

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

	September 30, 2014			June 30, 2014
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	23		$	5,601
Trade accounts receivable – net		67,385			72,301
Fair value of commodity derivative instruments		2,262			—
Deferred tax asset		24,587			24,587
Prepaid expenses		14,345			26,521
Total current assets		108,602			129,010
Property and equipment, under the full cost method of accounting, including $908.5 million of unevaluated properties not being amortized at September 30, 2014 and June 30, 2014		3,262,727			3,205,187
Goodwill		—			329,293
Restricted cash		6,023			6,023
Fair value of commodity derivative instruments		162			—
Other assets		143			317
Total assets	$	3,377,657		$	3,669,830
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	79,179		$	92,981
Due to EGC		29,975			4,960
Accrued expenses		181,754			161,518
Asset retirement obligations		39,831			39,831
Fair value of commodity derivative instruments		1,446			26,440
Total current liabilities		332,185			325,730
Long-term debt		1,023,033			1,025,566
Asset retirement obligations		232,419			232,864
Deferred tax liabilities		496,629			483,798
Fair value of commodity derivative instruments		—			2,140
Other		5			6
Total liabilities		2,084,271			2,070,104
Commitments and contingencies (Note 10)
Stockholder’s equity:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at September 30, 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 September 30, 2014 and June 30, 2014		—			—
Additional paid-in capital		1,599,341			1,599,341
Accumulated other comprehensive income (loss)		6,779			(6,252	)
Retained earnings (loss)		(312,734	)		6,637
Total stockholder’s equity		1,293,386			1,599,726
Total liabilities and stockholder’s equity	$	3,377,657		$	3,669,830

 
 
See accompanying notes to condensed consolidated financial statements.

2

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

	SUCCESSOR COMPANY			PREDECESSOR COMPANY
	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
Revenue:
Oil and natural gas	$	173,720		$	183,114
Other		389			878
Total revenue		174,109			183,992
Costs and expenses:
Lease operating		56,300			42,291
Transportation		625			974
Exploration expenditures and dry hole costs		—			5,146
Goodwill and other impairments		329,293			12
Depreciation, depletion and amortization		73,745			53,989
Accretion of liability for asset retirement obligations		6,181			6,266
General and administrative		8,042			6,426
Taxes, other than on earnings		2,528			3,285
Gain on sales of assets		—			(1,745	)
Other		21			26,534
Total costs and expenses		476,735			143,178
Income (loss) from operations		(302,626	)		40,814
Other income (expense):
Interest income		—			64
Interest expense		(10,901	)		(13,177	)
Loss on derivative instruments		(30	)		(30,012	)
Total other expense		(10,931	)		(43,125	)
Loss before income taxes		(313,557	)		(2,311	)
Deferred income tax expense (benefit)		5,814			(1,027	)
Net loss		(319,371	)		(1,284	)
Basic loss per share					(0.03	)
Diluted loss per share					(0.03	)
Weighted average common shares used in computing loss per share:
Basic					38,589
Diluted					38,589

 
 
See accompanying notes to condensed consolidated financial statements.

3

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

	Three Months Ended September 30, 2014
Net loss	$	(319,371	)
Other comprehensive income (loss)
Crude oil and natural gas cash flow hedges
Unrealized change in fair value net of ineffective portion		21,887
Effective portion reclassified to earnings during the period		(1,839	)
Total other comprehensive income		20,048
Income tax expense		(7,017	)
Net other comprehensive income		13,031
Comprehensive loss	$	(306,340	)

 
 
See accompanying notes to condensed consolidated financial statements.

4

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

	SUCCESSOR COMPANY			PREDECESSOR COMPANY
	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
Cash flows from operating activities:
Net income (loss)	$	(319,371	)	$	(1,284	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		73,745			53,989
Accretion of liability for asset retirement obligations		6,181			6,266
Change in fair value of derivative instruments		30			26,478
Non-cash compensation		—			1,910
Deferred income taxes		5,814			(1,052	)
Exploration expenditures		—			73
Goodwill and other impairments		329,293			12
Amortization of premium, discount and deferred financing costs on debt		(2,534	)		1,361
Gain on sales of assets		—			(1,745	)
Other		—			22,562
Changes in operating assets and liabilities:
Trade accounts receivable		6,410			8,542
Prepaid expenses		(5,873	)		549
Other assets		174			(1,361	)
Accounts payable and accrued expenses		(23,831	)		10,457
Asset retirement obligation settlements		(7,190	)		(10,072	)
Net cash provided by operating activities		62,848			116,685
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		—			51,757
Property acquisitions		(260	)		(24,897	)
Capital expenditures		(111,136	)		(100,021	)
Other property and equipment additions		(40	)		(254	)
Net cash used in investing activities		(111,436	)		(73,415	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		—			(40,000	)
Advances from EGC		43,010			—
Deferred financing costs		—			(32	)
Purchase of shares into treasury		—			(4,544	)
Exercise of stock options		—			360
Net cash provided by (used in) financing activities		43,010			(44,216	)
Net decrease in cash and cash equivalents		(5,578	)		(946	)
Cash and cash equivalents at beginning of period		5,601			3,885
Cash and cash equivalents at end of period	$	23		$	2,939

 
 
See accompanying notes to condensed consolidated financial statements.

5

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. (referred to herein as “we,” “our,” “us,” “the Company” or “EPL”) was incorporated as a Delaware corporation on January 29, 1998 and is a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation and indirect wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of Bermuda (“Energy XXI”). We operate as an independent oil and natural gas exploration and production company based in Houston, Texas and New Orleans, Louisiana.

Our current operations are 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. We have focused on acquiring and developing assets in this region, because the region is characterized by established exploitation, development and exploration opportunities in both productive horizons and deeper geologic formations.

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 our 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.

6

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

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

Interim Financial Statements.  The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in 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. 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 FASB issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers (ASU 2014-09). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our 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 public entities for annual and interim periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our financial position, results of operations or cash flows.

(2) Acquisitions and Dispositions

The South Pass 49 Acquisition

On June 3, 2014, we acquired from Energy XXI GOM, LLC, an asset package 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, subject to customary adjustments to reflect an economic effective date of June 1, 2014 (the “SP49 Acquisition”). We estimate that the proved reserves as of the June 1, 2014 economic effective date totaled approximately 11.3 Mmboe, of which 74% were oil and 73% were proved developed reserves. Prior to the SP49 Acquisition, 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 Acquisition, we have become the sole working interest owner of the South Pass 49 field. We financed the SP49 Acquisition with borrowings of approximately $135 million under our credit facility and a $95 million capital contribution from EGC. See Note 6, “Indebtedness” for more information regarding our credit facility.

7

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

(2) Acquisitions and Dispositions  – (continued)

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects management’s estimate of customary adjustments of $0.2 million to reflect an economic effective date of June 1, 2014.

(In thousands)	June 1, 2014
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 of 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”). Estimated proved reserves as of the September 1, 2013 effective date consisted of approximately 2.6 Mmboe of proved developed producing reserves, about 91% of which was oil. 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 management’s estimate of customary 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)	September 1, 2013
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”). We estimate that the proved reserves as of the January 1, 2013 economic effective date totaled approximately 0.7 Mmboe, of which 95% were oil and 58% were proved developed reserves. The WD29 Acquisition was funded with a portion of the proceeds from the sale of certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay Marchand field in a tax-deferred exchange of properties.

8

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

(2) Acquisitions and Dispositions  – (continued)

The following table summarizes the estimated values of assets acquired and liabilities assumed and reflects final adjustments to purchase price provided for by the purchase and sale agreement of approximately $7.1 million to reflect an economic effective date of January 1, 2013.

(In thousands)	January 1, 2013
Oil and natural gas properties	$	16,544
Asset retirement obligations		(1,398	)
Net assets acquired	$	15,146

We have accounted for our acquisitions using the acquisition method of accounting for business combinations, and therefore we have estimated the fair value of the assets acquired and the liabilities assumed as of their respective acquisition dates. In the estimation of fair value, management uses various valuation methods including (i) comparable company analysis, which estimates the value of the acquired properties based on the implied valuations of other similar operations; (ii) comparable asset transaction analysis, which estimates the value of the acquired operations based upon publicly announced transactions of assets with similar characteristics; (iii) comparable merger transaction analysis, which, much like comparable asset transaction analysis, estimates the value of operations based upon publicly announced transactions with similar characteristics, except that merger analysis analyzes public to public merger transactions rather than solely asset transactions; and (iv) discounted cash flow analysis. The fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 8, “Fair Value Measurements.”

Results of Operations and Pro Forma Information

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

	Three Months Ended September 30, 2014
	(In thousands)
SP49 Interests:
Revenues	$	14,980
Lease operating expenses	$	1,994
EI Interests:
Revenues	$	11,847
Lease operating expenses	$	4,265
WD29 Interests:
Revenues	$	3,843
Lease operating expenses	$	244

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.

9

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

(2) Acquisitions and Dispositions  – (continued)

The following supplemental pro forma information presents consolidated results of operations as if the WD 29 Acquisition, the Nexen Acquisition and the SP49 Acquisition had occurred on July 1, 2013. 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 acquisitions occurred on July 1, 2013, nor is such information indicative of any expected future results of operations.

	PRO FORMA
(in thousands, except per share data)	Three Months Ended September 30, 2013
Revenue	$	220,668
Net income		8,216
Basic earnings per share		0.21
Diluted earnings per share		0.21

(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 were recorded as goodwill. Goodwill recorded in connection with the Merger is not deductible for income tax purposes.

On April 2, 2013, we sold certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of production in the months of January 2013 and February 2013 totaling to approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed by Energy XXI in the Merger and a 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 on an annual basis for impairment or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. ASC 350 also specifically requires goodwill impairment testing at the subsidiary level using the subsidiary’s reporting units. EPL has only one 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, including macroeconomic conditions, industry and market conditions and other relevant factors. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a

10

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

(3) Pushdown Accounting and Goodwill  – (continued)

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 and an increase in the discount rate 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.

Because quoted market prices for our reporting unit are not available, management must apply judgment in determining the estimated fair value of the reporting unit for purposes of performing the goodwill impairment test. In estimating the fair value of our reporting unit, 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.

(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 period for the Predecessor Company.

	Three Months Ended September 30, 2013
Income (numerator):
Net loss	$	(1,284	)
Net income attributable to participating securities		—
Net loss attributable to common shares	$	(1,284	)
Weighted average shares (denominator):
Weighted average shares – basic		38,589
Dilutive effect of stock options		—
Weighted average shares – diluted		38,589
Basic loss per share	$	(0.03	)
Diluted loss per share	$	(0.03	)

11

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

(4) Earnings Per Share  – (continued)

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 September 30, 2013
	(in thousands)
Weighted average shares		1,037

(5) Asset Retirement Obligations

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

	Three Months Ended September 30, 2014
	(in thousands)
Beginning of period total	$	272,695
Accretion expense		6,181
Liabilities incurred		564
Liabilities settled		(7,190	)
End of period total		272,250
Less: End of period, current portion		(39,831	)
End of period, noncurrent portion	$	232,419

(6) Indebtedness

The following table sets forth our indebtedness.

	September 30, 2014		June 30, 2014
	(In thousands)
8.25% senior notes due 2018	$	548,033	$	550,566
Revolving credit sub-facility		475,000		475,000
Total indebtedness		1,023,033		1,025,566
Current portion of indebtedness		—		—
Noncurrent portion of indebtedness	$	1,023,033	$	1,025,566

8.25% Senior Notes

The 8.25% senior notes consist of $510.0 million in aggregate principal amount of our 8.25% senior notes due 2018 (the “8.25% Senior Notes”) 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.

12

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

(6) Indebtedness  – (continued)

Revolving Credit Sub-Facility

On June 3, 2014, EGC, EPL, the lenders thereunder and the other parties thereto entered into the Eighth Amendment dated May 23, 2014 (“the Eighth Amendment”) to the second amended and restated first lien credit agreement (“First Lien Credit Agreement”). The Eighth Amendment generally set out the consent of the lenders thereunder to the consummation of the acquisition of EPL by EGC on such date and contained provisions facilitating such acquisition, including providing some of the financing for it. Most of the terms of the Eighth Amendment generally are in regards to incorporating the concept of EPL as a separate “borrower” for purposes of the First Lien Credit Agreement. Pursuant to the Eighth Amendment, the borrowing base for EGC was established at $1.5 billion until the next redetermination of such borrowing base pursuant to the terms of the First Lien Credit Agreement. Of this borrowing base amount, EGC established a sub-facility pursuant to the Eighth Amendment for us with a borrowing base of $475 million (“Revolving Credit Sub-Facility”). The maturity date of the Revolving Credit Sub-Facility is April 9, 2018, provided that the facility maturity will accelerate if the EGC 9.25% senior notes are not retired or refinanced by June 15, 2017 or our 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%.

The borrowing base for this sub-facility is subject to redetermination from time to time generally on the same basis as is the overall borrowing base under the First Lien Credit Agreement. Under the Eighth Amendment, EGC and its subsidiaries, other than EPL, have guaranteed and secured the indebtedness of EPL and its subsidiaries, but EPL and its subsidiaries have not commensurately guaranteed the obligations of EGC and its other subsidiaries. However, per the terms of the First Lien Credit Agreement, immediately upon our retirement of our obligations in respect of our outstanding 8.25% Senior Notes due 2018, we are required to guarantee and secure the obligations generally of EGC and its subsidiaries and our sub-facility shall terminate and the entire borrowing base amount shall thereupon be available to EGC for credit extensions under the terms of the First Lien Credit Agreement.

On September 5, 2014, the Ninth Amendment to the First Lien Credit Agreement became effective (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 our 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. 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.

13

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

(7) Derivative Instruments and Hedging Activities

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 Fair value of commodity derivative instruments. Prior to the Merger, we did not designate derivative instruments as hedges. 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 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 financial instruments, whereas gains and losses from the settlement of cash flow hedging contracts are recorded in crude oil and natural gas revenue in the same period during which the hedged transactions are settled. See Note 8 for information regarding fair values of our derivative instruments.

Energy XXI assumed our existing hedges and expects to carry those hedges through the end of contract term beginning from June 2014 through December 2015. Our oil contracts are primarily swaps and benchmarked to Argus-LLS and Brent.

The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.

The following tables set forth our derivative instruments outstanding as of September 30, 2014.

Oil Contracts

	Fixed-Price Swaps
Remaining Contract Term	Daily Average Volume (Bbls)		Volume (Bbls)		Average Swap Price ($/Bbl)
October 2014 – December 2014		7,744		712,450		91.95
January 2015 – December 2015		1,500		547,500		97.70

Gas Contracts

Remaining Contract Term	Type of Contract		Volume (Mmbtu)		Average Swap Price ($/Mmbtu)		Weighted Average Contract Price ($/Mmbtu)
							Sub Floor		Floor		Ceiling
October 2014 – December 2014		Three-Way Collars		703,000				3.25		4.00		4.76
October 2014 – December 2014		Put Spreads		217,000				3.25		4.00
October 2014 – December 2014		Fixed Price Swaps		460,000		4.01
January 2015 – December 2015		Fixed Price Swaps		1,569,500		4.31

For the three months ended September 30, 2014, we reclassified from AOCI a gain of approximately $1.8 million to oil and natural gas revenue. The amount expected to be reclassified from other comprehensive income to income in the next 12 months is a gain of $9.8 million ($6.4 million net of tax) on our commodity hedges. The estimated and actual amounts are likely to vary significantly due to changes in market conditions.

14

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

(7) Derivative Instruments and Hedging Activities  – (continued)

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

	SUCCESSOR COMPANY			PREDECESSOR COMPANY
	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
Location of (Gain) Loss in Income Statement
Cash Settlements
Oil sales	$	(2,013	)	$	—
Natural gas sales		174			—
Total cash settlements		(1,839	)		—
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		26			3,534
Unrealized mark to market loss		1			26,478
Total loss on derivative financial instruments		30			30,012
Total (gain) loss	$	(1,809	)	$	30,012

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

(8) 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 September 30, 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 commodity derivative 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 commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity

15

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

(8) Fair Value Measurements  – (continued)

derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. 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.

	September 30, 2014			June 30, 2014
	(in thousands)
Assets
Commodity Derivative Instruments designated as hedging instruments
Current	$	3,272		$	—
Noncurrent		162			—
Total gross commodity derivative instruments subject to enforceable netting agreement		3,434			—
Gross amounts offset in Balance sheet		(1,010	)		—
Net amounts presented in Balance sheet	$	2,424		$	—
Liabilities
Commodity Derivative Instruments designated as hedging instruments
Current	$	2,456		$	26,440
Noncurrent		—			2,140
Total gross commodity derivative instruments subject to enforceable netting agreement		2,456			28,580
Gross amounts offset in Balance sheet		(1,010	)		—
Net amounts presented in Balance sheet	$	1,446		$	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.

	September 30, 2014				June 30, 2014
	(In thousands)
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
8.25% Senior Notes	$	548,033	$	519,139	$	550,566	$	545,700
Revolving credit sub-facility		475,000		475,000		475,000		475,000
Total	$	1,023,033	$	994,139	$	1,025,566	$	1,020,700

16

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

(8) Fair Value Measurements  – (continued)

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.

(9) 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 September 30, 2014 was approximately $4.0 million, of which $3.7 million is included in general and administrative expense.

(10) Commitments and Contingencies

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

1) April 1, 2014 to October 12, 2014 at $112,000 per day.

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

3) October 1, 2014 to December 29, 2014 at $111,380 per day.

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

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 allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, EGC, Merger Sub, and EPL (the “Merger Agreement”), including that (a) our directors have allegedly breached fiduciary duties in connection with the Merger and (b) we along with Energy XXI, EGC, and Merger Sub, allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the Merger allegedly provided inadequate consideration to our stockholders for their shares of our common stock; (ii) the Merger Agreement contained contractual terms —  including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of our common stock; (iii) certain of our officers and directors allegedly received benefits — including (A) an offer

17

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

(10) Commitments and Contingencies  – (continued)

for one of our directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by our executive officers — that were not equally shared by our stockholders; (iv) Energy XXI required our officers and directors to agree to vote their shares of our common stock in favor of the Merger; and (v) we provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire us for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by us and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the Merger, (ii) our efforts to attract offers from other potential acquirors, (iii) our evaluation of the Merger; (iv) negotiations between us and Energy XXI, and (v) the analysis of our financial advisor. Based on these allegations, plaintiffs seek to have the Merger Agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. We cannot predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this Quarterly Report; nor can we predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

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 September 30, 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 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.

(11) Subsequent Events

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

(12) Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 6, 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

18

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

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

“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.

19

SUCCESSOR COMPANY
 
Supplemental Condensed Consolidating Balance Sheet
As of September 30, 2014
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	23		$	—	$	—		$	23
Trade accounts receivable – net		67,242			143		—			67,385
Intercompany receivables		—			32,088		(32,088	)		—
Fair value of commodity derivative instruments		2,262			—		—			2,262
Deferred tax asset		24,587			—		—			24,587
Prepaid expenses		14,345			—		—			14,345
Total current assets		108,459			32,231		(32,088	)		108,602
Net property and equipment		3,094,134			168,593		—			3,262,727
Investment in affiliates		129,772			—		(129,772	)		—
Restricted cash		6,023			—		—			6,023
Fair value of commodity derivative instruments		162			—		—			162
Other assets		53			90		—			143
Total assets	$	3,338,603		$	200,914	$	(161,860	)	$	3,377,657
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	78,565		$	614	$	—		$	79,179
Intercompany payables		32,088			—		(32,088	)		—
Accrued expenses		181,739			15		—			181,754
Asset retirement obligations		34,041			5,790		—			39,831
Fair value of commodity derivative instruments		1,446			—		—			1,446
Due to EGC		29,975			—		—			29,975
Total current liabilities		357,854			6,419		(32,088	)		332,185
Long-term debt		1,023,033			—		—			1,023,033
Asset retirement obligations		192,750			39,669		—			232,419
Deferred tax liabilities		471,575			25,054		—			496,629
Other		5			—		—			5
Total liabilities		2,045,217			71,142		(32,088	)		2,084,271
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		6,779			—		—			6,779
Retained earnings (loss)		(312,734	)		44,293		(44,293	)		(312,734	)
Total stockholder’s equity		1,293,386			129,772		(129,772	)		1,293,386
Total liabilities and stockholder’s equity	$	3,338,603		$	200,914	$	(161,860	)	$	3,377,657

20

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
Intercompany payables		26,311			—		(26,311	)		—
Accrued expenses		161,503			15		—			161,518
Asset retirement obligations		33,357			6,474		—			39,831
Fair value of commodity derivative instruments		26,440			—		—			26,440
Due to EGC		4,960			—		—			4,960
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
Fair value of commodity derivative 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 income (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

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SUCCESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2014
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	156,093		$	17,627	$	—		$	173,720
Other		318			71		—			389
Total revenue		156,411			17,698		—			174,109
Costs and expenses:
Lease operating		52,574			3,726		—			56,300
Transportation		624			1		—			625
Goodwill and other impairments		329,293			—		—			329,293
Depreciation, depletion and amortization		68,005			5,740		—			73,745
Accretion of liability for asset retirement obligations		5,343			838		—			6,181
General and administrative		8,042			—		—			8,042
Taxes, other than on earnings		105			2,423		—			2,528
Other		21			—		—			21
Total costs and expenses		464,007			12,728		—			476,735
Income (loss) from operations		(307,596	)		4,970		—			(302,626	)
Other income (expense):
Interest expense		(10,901	)		—		—			(10,901	)
Loss on derivative instruments		(30	)		—		—			(30	)
Income from equity investments		3,134			—		(3,134	)		—
Total other income (expense)		(7,797	)		—		(3,134	)		(10,931	)
Income (loss) before provision for income taxes		(315,393	)		4,970		(3,134	)		(313,557	)
Deferred income tax expense		3,978			1,836		—			5,814
Net income (loss)	$	(319,371	)	$	3,134	$	(3,134	)	$	(319,371	)

22

PREDECESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Operations
Three Months Ended September 30, 2013
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
Revenue:
Oil and natural gas	$	159,902		$	23,212	$	—		$	183,114
Other		127			751		—			878
Total revenue		160,029			23,963		—			183,992
Costs and expenses:
Lease operating		35,995			6,296		—			42,291
Transportation		974			—		—			974
Exploration expenditures and dry hole costs		5,145			1		—			5,146
Goodwill and other impairments		12			—		—			12
Depreciation, depletion and amortization		48,451			5,538		—			53,989
Accretion of liability for asset retirement obligations		5,077			1,189		—			6,266
General and administrative		6,426			—		—			6,426
Taxes, other than on earnings		225			3,060		—			3,285
Gain on sale of assets		(1,745	)		—					(1,745	)
Other		26,407			127		—			26,534
Total costs and expenses		126,967			16,211		—			143,178
Income from operations		33,062			7,752		—			40,814
Other income (expense):
Interest income		64			—		—			64
Interest expense		(13,177	)		—		—			(13,177	)
Gain on derivative instruments		(30,012	)		—		—			(30,012	)
Income from equity investments		4,930			—		(4,930	)		—
Total other income (expense)		(38,195	)		—		(4,930	)		(43,125	)
Income (loss) before provision for income taxes		(5,133	)		7,752		(4,930	)		(2,311	)
Deferred income tax expense (benefit)		(3,849	)		2,822		—			(1,027	)
Net income (loss)	$	(1,284	)	$	4,930	$	(4,930	)	$	(1,284	)

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SUCCESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Cash Flows
Three Months Ended September 30, 2014
(UNAUDITED)

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

PREDECESSOR COMPANY
 
Supplemental Condensed Consolidating Statement of Cash Flows
Three Months Ended September 30, 2013
(UNAUDITED)

	Parent Company Only			Guarantor Subsidiaries			Eliminations		Consolidated
	(In thousands)
Net cash provided by operating activities	$	99,497		$	17,188		$	—	$	116,685
Cash flows provided by (used in) investing activities:
Decrease in restricted cash		51,757			—			—		51,757
Property acquisitions		(24,897	)		—			—		(24,897	)
Capital expenditures		(82,833	)		(17,188	)		—		(100,021	)
Other property and equipment additions		(254	)		—			—		(254	)
Net cash used in investing activities		(56,227	)		(17,188	)		—		(73,415	)
Cash flows provided by (used in) financing activities:
Repayments of indebtedness		(40,000	)		—			—		(40,000	)
Deferred financing costs		(32	)		—			—		(32	)
Purchase of shares into treasury		(4,544	)		—			—		(4,544	)
Exercise of stock options		360			—			—		360
Net cash used in financing activities		(44,216	)		—			—		(44,216	)
Net decrease in cash and cash equivalents		(946	)		—			—		(946	)
Cash and cash equivalents at beginning of period		3,885			—			—		3,885
Cash and cash equivalents at end of period	$	2,939		$	—		$	—	$	2,939

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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 operates in a single segment as an independent oil and natural gas exploration and production company. Our current operations are 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. We have focused on acquiring and developing assets in this region, as it offers a balanced and expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations.

On June 3, 2014, Energy XXI Ltd, an exempted company under the laws of Bermuda (“Energy XXI”), Energy XXI Gulf Coast, Inc. (“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.

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

25

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.

Subsequent to the Merger, we adopted the full cost method of accounting for exploration and development activities. Under this 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 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.

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 statements for the three months ending September 30, 2014 (reflecting operations of the Successor Company) are not comparable to those for the three months ending September 30, 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 $200 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.

We continue to generate prospects, strive to maintain an extensive inventory of drillable prospects in-house and maintain exposure to new opportunities through relationships with industry partners. Our longer term operating strategy is to increase our oil and natural gas reserves and production while focusing on exploration and development costs and operating costs to remain competitive with our offshore Gulf of Mexico industry peers.

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

26

availability of other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate, or WTI, has ranged from a high of $145.31 per barrel, or Bbl, in July 2008 to a low of $30.28 per Bbl in December 2008. The Henry Hub spot market price of natural gas has ranged from a high of $13.31 per million British thermal units, or MMBtu, in July 2008 to a low of $1.82 per MMBtu in April 2012. During 2013, West Texas Intermediate prices ranged from $85.61 to $112.24 per Bbl and the Henry Hub spot market price of natural gas ranged from $3.05 to $4.53 per MMBtu. Oil prices have recently experienced substantial declines. For example, the price of West Texas Intermediate crude has declined from an average of $95.03 per Bbl in September 2014 to below $80.00 per Bbl at the end of October 2014. Sustained periods of low prices for oil and natural gas could have a material adverse effect on our financial position, our results of operations, our cash flows, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. 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.

RESULTS OF OPERATIONS

The following table presents information about our oil and natural gas operations.

	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
Net production (per day):
Oil (Bbls)		18,063			17,481
Natural gas (Mcf)		38,735			33,696
Total (Boe)		24,519			23,097
Average sales prices(1):
Oil (per Bbl)	$	96.24		$	106.85
Natural gas (per Mcf)		3.87			3.63
Total (per Boe)		77.01			86.17
Oil and natural gas revenues (in thousands):
Oil	$	159,940		$	171,847
Natural gas		13,780			11,267
Total		173,720			183,114
Impact of derivatives instruments settled during the period(1):
Oil (per Bbl)				$	(2.18	)
Natural gas (per Mcf)					(0.01	)
Average costs (per Boe):
LOE	$	24.96		$	19.90
Taxes, other than on earnings		1.12			1.55
General and administrative (“G&A”) expenses		3.57			3.02
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil	$	(17,059	)
Changes in production volumes of oil		5,152
Total decrease in oil sales		(11,907	)
Changes in prices of natural gas	$	737
Changes in production volumes of natural gas		1,776
Total increase in natural gas sales		2,513

27

(1) For the three months ended September 30, 2014, our oil and natural gas revenues and resulting average sales prices include the impact of accounting for our derivative instruments as cash flow hedges.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013

Overview

Our operating results for the three months ended September 30, 2014, compared to the three months ended September 30, 2013, reflect a 3% increase in oil production and a 15% increase in natural gas production. Our product mix for the three months ended September 30, 2014 was 74% oil (including natural gas liquids) compared to 76% for the three months ended September 30, 2013.

Revenue

	Three Months Ended September 30, 2014		Three Months Ended September 30, 2013
	(in thousands)		(in thousands)		$ Change			% Change
Oil and natural gas revenues	$	173,720	$	183,114	$	(9,394	)		-5	%

For the three months ended September 30, 2014, our oil and natural gas revenues decreased 5% as compared to the three months ended September 30, 2013, due primarily to a 10% decrease in average selling prices for our oil partially offset by a 3% increase in oil production. The decrease in our oil revenues was also partially offset by an increase in natural gas revenues, primarily due to a 15% increase in natural gas production and a 7% increase in average selling prices for natural gas in the three months ended September 30, 2014, as compared to the three months ended September 30, 2013. In addition, revenues for the three months ended September 30, 2014 include $1.8 million from the impact of hedge accounting.

Our overall average selling prices decreased by 11% for the three months ended September 30, 2014 when compared to the three months ended September 30, 2013. Commodity prices are one of the key drivers of earnings generation and net operating cash flow. Average crude oil prices, including a $1.31 realized gain per barrel related to hedging activities, decreased $10.61 per barrel in the first quarter of fiscal 2015, resulting in lower revenues of approximately $17.1 million. Average natural gas prices, including a $0.05 realized loss per Mcf related to hedging activities, increased $0.24 per Mcf in the first quarter of fiscal 2015, resulting in higher revenues of approximately $0.7 million. Commodity prices are affected by many factors outside of our control. Therefore, commodity prices we received during the first quarter of fiscal 2015 are not necessarily indicative of prices we may receive in the future. Depressed commodity prices over a period of time could result in reduced cash flow from operating activities, potentially causing us to spend less on our capital program. Lower spending on our capital program could result in a reduction in production volumes. We cannot accurately predict future commodity prices, and cannot be certain whether these events will occur.

Our overall production volumes increased by 6% for the three months ended September 30, 2014 when compared to the three months ended September 30, 2013. Our GoM shelf production increased 6% in the three months ended September 30, 2014, as compared to the three months ended September 30, 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 1,419 Boe per day and 3,332 Boe per day for the quarter ended September 30, 2014, respectively. These increases were partially offset by decreases in production in our West Delta and Main Pass fields.

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Operating Expenses

Our operating expenses primarily consist of the following:

	Three Months Ended September 30, 2014		Three Months Ended September 30, 2013
	(in thousands)		(in thousands)		$ Change			% Change
LOE	$	56,300	$	42,291	$	14,009			33	%
Exploration expenditures and dry hole costs(1)		—		5,146		NM			NM
Goodwill and other impairments		329,293		12		NM			NM
DD&A, including accretion expense(1)		79,926		60,255		NM			NM
G&A expenses		8,042		6,426		1,616			25	%
Taxes, other than on earnings		2,528		3,285		(757	)		-23	%
Other		21		26,534		(26,513	)		-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. SeeOverview.

LOE increased for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013, primarily due to the acquisition of the EI Interests and SP 49 Interests. LOE for the three months ended September 30, 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 three months ended September 30, 2013, we recorded approximately $3.0 million of exploratory expenses. In addition, exploration expenditures include $2.1 million in seismic expense during the three months ended September 30, 2013.

During the three months ended 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 the discount rate 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. As a result, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at September 30, 2014.

G&A expenses increased for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013, primarily as a result of approximately $3.7 million of intercompany service fees expensed during the three months ended September 30, 2014.

Other operating expenses decreased for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013, primarily as a result of a decrease in loss on abandonment activities. During the three months ended September 30, 2013, we recorded a loss on abandonment activities of $22.6 million. Additionally, during the three months ended September 30, 2013, we recorded amortization expense related to our weather derivative of $4.0 million. For the three months ended September 30, 2013, our loss on abandonment activities primarily reflects 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.

29

Other Income and Expense

Interest expense decreased approximately $2.3 million for the three months ended September 30, 2014, as compared to the three months ended September 30, 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 September 30, 2013 includes a net loss on derivative instruments of $30.0 million consisting of an unrealized loss of $26.5 million due to the change in fair value of derivative instruments to be settled in the future and a net realized loss of $3.5 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

Our estimated effective income tax rate for the three months ended September 30, 2014 was 37.0%, excluding the impact of the goodwill impairment charge during the period which is not deductible for income tax purposes. Our estimated effective income tax rate for the three months ended September 30, 2013 was 36.4%. The increase in our estimated effective income tax rate is primarily related to our estimated state income taxes.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We have historically funded our operations primarily through cash flows from operations, borrowings under our revolving credit facility and the issuance of debt securities. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. Significant declines in commodity prices would negatively impact revenues, earnings and cash flows and potentially our liquidity if we do not reduce our spending accordingly. Cash investments are required to fund activities necessary to offset the natural production declines in proved reserves. Our ability to maintain and grow reserves is dependent on the success of our exploration and development activity and our ability to acquire additional reserves at reasonable rates.

Our Indebtedness and Available Credit

As of September 30, 2014, we had $475 million in borrowings outstanding under the first lien credit agreement, as amended (“First Lien Credit Agreement”), to which we are party with EGC. Effective June 3, 2014, EPL, EGC, the lenders thereunder and the other parties thereto, entered into the Eighth Amendment, dated May 23, 2014 (“the Eighth Amendment”) to the First Lien Credit Agreement which generally set out the consent of the lenders thereunder to consummate the acquisition by EGC of EPL and contained provisions facilitating such acquisition, including providing some of the financing for it. Pursuant to the Eighth Amendment, the borrowing base for EGC was established at $1.5 billion. Of this borrowing base amount, EGC established a sub-facility pursuant to the Eighth Amendment for EPL, with a borrowing base of $475 million for such sub-facility (our “Revolving Credit Sub-Facility”). Upon the effectiveness of the Eighth Amendment, we immediately borrowed the entire $475 million to refinance the outstanding indebtedness we had under the terms of our prior senior credit facility in existence at the effective time of the Merger.

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 November 11, 2014, we have fully utilized amounts available under our Revolving Credit Sub-Facility. For more information on our Revolving Credit Sub-Facility, see Note 6, “Indebtedness,” in the condensed consolidating financial statements in Part 1, Item 1 of this Quarterly Report.

30

If commodity prices continue to decline, EGC’s borrowing base and 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. In addition, we would have to repay any outstanding indebtedness in excess of any reduced borrowing base.

At September 30, 2014, we also 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 the success of our development activities, our ability to maintain and grow reserves, oil and gas prices and our ability to refinance our debt as it becomes due. While we expect to fund the majority of future capital expenditures with cash flow from operations, we depend on the availability of borrowings and equity investments from EGC as a source of liquidity, including for short-term working capital requirements. Although credit and equity markets have rebounded significantly in recent years following the credit crisis, our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations 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. At present, we believe that our liquidity and capital resources alternatives available to us will be adequate to meet our funding requirements through September 30, 2015.

Capital Expenditures

For fiscal 2015, our capital expenditures are now estimated at $200 million. During the three months ended September 30, 2014, we incurred capital costs of approximately $128 million on our development and exploration program. Additionally, we spent approximately $7.2 million in the three months ended September 30, 2014 on plugging, abandonment and other decommissioning activities. 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 believe that our available liquidity is sufficient to meet our capital requirements through September 30, 2015. We currently expect to fund our 2015 capital program primarily from existing cash flow from operations and borrowings and equity investments from EGC. However, these cash flows are dependent upon future production volumes and commodity prices and there can be no assurance that cash flow from operations or other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. If our cash flows from operations 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 natural gas and oil sales prices, costs of drilling and completion, drilling results and changes in the borrowing base under the First Lien Credit Agreement and available funding from EGC.

Analysis of Cash Flows — Three Months Ended September 30, 2014

The following table sets forth our cash flows:

	Three Months Ended September 30, 2014			Three Months Ended September 30, 2013
	(In thousands)			(In thousands)
Net cash provided by operating activities	$	62,848		$	116,685
Net cash used in investing activities		(111,436	)		(73,415	)
Net cash provided by (used in) financing activities		43,010			(44,216	)

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 three months ended September 30, 2014, as compared to the three months ended September 30, 2013.

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Net cash used in investing activities increased for the three months ended September 30, 2014, as compared to the three months ended September 30, 2013, due to an increase in capital expenditures in the three months ended September 30, 2014. In addition, net cash used in investing activities for the three months ended September 30, 2013, is net of the reduction of restricted cash of $51.8 million associated with the sale of interests in the Bay Marchand field and used to fund the WD29 Acquisition.

Net cash provided by financing activities during the three months ended September 30, 2014 reflects $43.0 million in advances from EGC. Net cash used in financing activities during the three months ended September 30, 2013 reflects $40.0 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.

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 September 30, 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 probably 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 fluctuate widely. Oil and natural gas price declines and volatility could adversely affect our revenues, cash flows and profitability. Prices also affect the amount of cash flow available for

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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. If commodity prices deteriorate materially, the borrowing base could be reduced, which would require us to repay a portion of our outstanding indebtedness. Price volatility is expected to continue.

We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas associated with future oil and natural gas production and not for speculative purposes. We also use financially settled crude oil and natural gas puts, 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. 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 September 30, 2014, our natural gas contracts outstanding had an asset position of $0.5 million. A 10% increase in natural gas prices would reduce the fair value by approximately $0.9 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.9 million. Also, at September 30, 2014, our crude oil contracts outstanding had an asset position of $0.5 million. A 10% increase in crude oil prices would reduce the fair value by approximately $13.6 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $13.6 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2014. See Note 8, “Fair Value Measurements,” of the condensed consolidated financial statements in Part I, Item 1 of this Quarterly Report.

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

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our Revolving Credit Sub-Facility. As of September 30, 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 September 30, 2014. A 10 percent change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $15,000. 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

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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 September 30, 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 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 September 30, 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 10, “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 to the risk factors set forth in our 2014 Transition Report.

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: November 12, 2014	By: /s/ Rick D. Fox Rick D. Fox Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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INDEX TO EXHIBITS

Exhibit Number	Exhibit Description	Incorporated by Reference Form	SEC File Number	Exhibit	Filing Date	Filed/ Furnished Herewith
2.1	Purchase and Sale Agreement dated June 3, 2014 by and between Energy XXI GOM, LLC, as seller, and EPL Oil & Gas, Inc., as purchaser	8-K	001-16179	2.1	9/3/2014
3.1	Amended and Restated Certificate of Incorporation of Energy Partners, Ltd. dated as of September 21, 2009	8-A/A	001-16179	3.1	9/21/2009
3.2	Third Amended and Restated Bylaws of EPL Oil & Gas, Inc.	8-K	001-16179	3.1	10/18/2012
3.3	Fourth Amended and Restated Bylaws of EPL Oil & Gas, Inc.	8-K	001-16179	3.2	6/3/2014
3.4	Certificate of Ownership and Merger filed with the Secretary of State of the State of Delaware, which became effective by its terms on September 1, 2012	8-K	001-16179	3.1	9/5/2012
3.5	Composite copy of the Third Amended and Restated Bylaws of EPL Oil & Gas, Inc., reflecting all amendments through March 11, 2014, the effective date of the Amendment to the Third Amended and Restated Bylaws	10-Q	001-16179	3.1	5/8/2014
3.6	Amended and Restated Certificate of Incorporation of EPL Oil & Gas, Inc., adopted June 3, 2014	8-K	001-16179	3.1	6/3/2014
10.1	Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of August 22, 2014, by and between Energy XXI Gulf Coast, Inc., EPL Oil & Gas, Inc., the various financial institutions thereto, as lenders, and The Royal Bank of Scotland plc, as Administrative Agent.	8-K	001-16179	10.1	9/3/2014
10.2	Eighth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 23, 2014, and effective as of June 3, 2014.	8-K	001-16179	10.2	9/3/2014
10.3	Ninth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of September 5, 2014.	8-K	001-16179	10.1	9/9/2014

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Exhibit Number	Exhibit Description	Incorporated by Reference Form	SEC File Number	Exhibit	Filing Date	Filed/ Furnished Herewith
31.1	Certification of Principal Executive Officer of EPL Oil & Gas, Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended					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
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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