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, 2015
or

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

Commission file number: 001-16179

 

EPL Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)

 

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

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

(713) 351-3000

Registrant’s telephone number, including area code

 

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

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

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

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

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

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

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

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		Page
PART I — FINANCIAL INFORMATION
Item 1. Unaudited Consolidated Financial Statements			1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			24
Item 3. Quantitative and Qualitative Disclosures about Market Risk			36
Item 4. Controls and Procedures			37
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			39
Item 1A. Risk Factors			39
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			39
Item 3. Defaults Upon Senior Securities			39
Item 4. Mine Safety Disclosures			39
Item 5. Other Information			39
Item 6. Exhibits			39
SIGNATURES			40
EXHIBIT INDEX			41

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

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PART I — FINANCIAL INFORMATION

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

		September 30, 2015				June 30, 2015
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	217
Trade accounts receivable – net			55,146				71,323
Derivative financial instruments			1,970				888
Restricted cash			6,025				6,024
Prepaid expenses			1,523				1,831
Total current assets			64,664				80,283
Property and equipment, net – full cost method of accounting, including $397.7 million and $435.4 million of unevaluated properties not being amortized at September 30, 2015 and June 30, 2015, respectively			1,053,954				1,415,025
Restricted cash			21,008				—
Other assets and debt issuance costs, net of accumulated amortization			947				1,039
Total assets		$	1,140,573			$	1,496,347
LIABILITIES AND STOCKHOLDER'S DEFICIT
Current liabilities:
Accounts payable		$	42,797			$	24,548
Due to EGC			190,401				170,728
Accrued liabilities			71,550				95,981
Asset retirement obligations			15,839				38,056
Derivative financial instruments			—				1,057
Current maturities of long-term debt			1,684				3,364
Total current liabilities			322,271				333,734
Long-term debt, less current maturities			686,018				689,459
Promissory note payable to EGC			325,000				325,000
Asset retirement obligations			196,004				202,306
Total liabilities			1,529,293				1,550,499
Commitments and contingencies (Note 10)
Stockholder's deficit:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at September 30, 2015 and June 30, 2015			—				—
Common stock, par value $0.001 per share. Authorized 75,000,000 shares; shares issued and outstanding: 1,000 at September 30, 2015 and June 30, 2015			—				—
Additional paid-in capital			1,599,341				1,599,341
Accumulated deficit			(1,988,061	)			(1,653,493	)
Total stockholder's deficit			(388,720	)			(54,152	)
Total liabilities and stockholder's deficit		$	1,140,573			$	1,496,347

 
 
See accompanying Notes to Consolidated Financial Statements.

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

		Three Months Ended September 30,
		2015				2014
Revenues
Oil sales		$	73,372			$	158,316
Natural gas sales			12,618				13,954
Gain on derivative financial instruments			2,778				21,857
Total Revenues			88,768				194,127
Costs and expenses
Lease operating			26,153				56,300
Transportation			723				625
Depreciation, depletion and amortization			57,660				73,745
Accretion of asset retirement obligations			6,741				6,181
Impairment of oil and natural gas properties			308,078				—
Goodwill impairment			—				329,293
General and administrative expense			7,944				8,042
Taxes, other than on earnings			(935	)			2,528
Other			—				21
Total costs and expenses			406,364				476,735
Operating Loss			(317,596	)			(282,608	)
Other income (expense):
Interest income			12				—
Interest expense			(16,984	)			(10,901	)
Total other expense, net			(16,972	)			(10,901	)
Loss before income taxes			(334,568	)			(293,509	)
Income tax expense			—				12,847
Net loss		$	(334,568	)		$	(306,356	)

 
 
See accompanying Notes to Consolidated Financial Statements.

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

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

 
 
See accompanying Notes to Consolidated Financial Statements.

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

(1) Organization and Summary of Significant Accounting Policies

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

Principles of Consolidation and Reporting.  The accompanying consolidated financial statements include the accounts of EPL and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions are eliminated in consolidation. Our interest in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

Interim Financial Statements.  The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our 2015 Annual Report.

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

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

In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s

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

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

ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.

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

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

In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805) —  Simplifying the Accounting for Measurement-Period Adjustments (“ASU 2015-16”). ASU 2015-16 requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. It also requires that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied prospectively. We are currently evaluating the provisions of ASU 2015-16 and assessing the impact, if any, it may have on our consolidated financial statements.

(2) Pushdown Accounting and Goodwill

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

In accordance with the acquisition method of accounting, the purchase price established in the Merger was allocated to the assets acquired and liabilities assumed based on their estimated fair values on the

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

(2) Pushdown Accounting and Goodwill  – (continued)

acquisition date. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the Merger is not deductible for income tax purposes.

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

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

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

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

(3) Property and Equipment

The following table summarizes our property and equipment.

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

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

(3) Property and Equipment  – (continued)

At September 30, 2015 and June 30, 2015, our investment in unevaluated properties primarily relates to the fair value of unproved oil and natural gas properties determined during the Merger. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.

Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. At September 30, 2015, our ceiling test computations resulted in impairment of our oil and natural gas properties of $308.1 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

(4) Asset Retirement Obligations

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

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

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

(5) Indebtedness

The following table sets forth our indebtedness.

		September 30, 2015				June 30, 2015
		(In thousands)
8.25% senior notes due 2018		$	536,018			$	539,459
Revolving credit sub-facility			150,000				150,000
Derivative instruments premium financing			1,684				3,364
Total debt			687,702				692,823
Less current maturities			(1,684	)			(3,364	)
Long term debt			686,018				689,459
Promissory note payable to EGC			325,000				325,000
Noncurrent portion of indebtedness		$	1,011,018			$	1,014,459

Revolving Credit Sub-Facility

On July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver (the “Eleventh Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”). This facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement (“Revolving Credit Sub-Facility”). The scheduled date of maturity of the First Lien Credit Agreement is April 9, 2018, provided however that the maturity date will accelerate to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of our outstanding 8.25% senior notes due February 2018 (the “8.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018.

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

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

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

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

(5) Indebtedness  – (continued)

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

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

The First Lien Credit Agreement, as amended, requires that EPL and EGC maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. We are currently subject to the following financial covenants: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If the 8.25% Senior Note are no longer outstanding and certain other conditions are met, EGC will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.

Since required lender consent to the specific terms of the transaction with respect to the sale of the East Bay field had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required us to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC.

As of September 30, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are party with EGC, and we were in compliance with all covenants thereunder. As part of our quarterly compliance certificates required under our revolving credit agreement and also as a condition to borrow funds or issue letters of credit under our revolving credit agreement, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in our revolving credit facility, as amended to date. Generally, the solvency representation requires, among other things, for us to determine at the time we desire to make a future borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation. In addition, based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods, including periods prior to June 30, 2016. We continue to focus on reducing our leverage and are working with our bank group on certain amendments to the First Lien Credit Agreement to address these concerns. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the

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

(5) Indebtedness  – (continued)

Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

Promissory Note

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

8.25% Senior Notes

The 8.25% senior notes consist of $510.0 million in aggregate principal amount ($536.0 million carrying value at September 30, 2015) of our 8.25% senior notes due 2018 (the “8.25% Senior Notes”) issued under an Indenture dated February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes bear interest from the date of their issuance at an annual rate of 8.25% with interest due semi-annually, in arrears, on February 15^th and August 15^th of each year. The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. As a result of pushdown accounting, the effective interest rate on the 8.25% Senior Notes is approximately 5.8%.

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

Derivative Instruments Premium Financing

We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Sub-Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Sub-Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of September 30, 2015, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $1.7 million.

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

(5) Indebtedness  – (continued)

Interest Expense

For the three months ended September 30, 2015 and 2014, interest expense consisted of the following:

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

(6) Derivative Financial Instruments

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

The following table sets forth our derivative instruments outstanding as of September 30, 2015.

Oil Contracts

Remaining Contract Term

Type of Contract

Index

Volume (MBbls)

Weighted Average Contract Price

Sub Floor

Floor

Ceiling

October 2015 –  December 2015

Three-Way Collars

ARGUS-LLS

1,012

$

32.73

$

45.00

$

75.45

Gas Contracts

Remaining Contract Term

Type of Contract

Index

Volume (MMBtu)

Swap Fixed Price (4/Mmbtu)

October 2015 – December 2015

Fixed Price Swaps

NYMEX-HH

369

$

4.31

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

(6) Derivative Financial Instruments  – (continued)

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

Gain (loss) on derivative financial instruments		Three Months Ended September 30,
		2015				2014
Cash settlements, net of purchased put premium amortization		$	714			$	1,812
Change in fair value			2,064				20,045
Total gain on derivative financial instruments		$	2,778			$	21,857

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, 2015, we had no deposits for collateral with our counterparties.

(7) Fair Value Measurements

Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

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

Our commodity derivative instruments consist of financially settled crude oil and natural gas swaps and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of

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

(7) Fair Value Measurements  – (continued)

commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 6 — Derivative Financial Instruments.

During the three months ended September 30, 2015, we did not have any transfers from or to Level 3. The following table sets forth our financial assets and liabilities that are accounted for at fair value on a recurring basis.

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

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

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

The 8.25% Senior Notes contain an option to redeem up to 35% of the aggregate principal amount of the notes outstanding with the net cash proceeds of certain equity offerings. This option is considered an embedded derivative and is classified as a Level 3 financial instrument for which the estimated fair value at September 30, 2015 is not material.

(8) Income Taxes

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

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

(8) Income Taxes  – (continued)

amounts presented in the separate financial statements of a subsidiary entity that is a member of a consolidated group should be based upon a reasonable allocation of the income tax amounts of that group. We allocate income tax expense/benefit and deferred tax items between affiliates as if each affiliate prepared a separate U.S. income tax return for the reporting period. We have recorded no income tax-related intercompany balances with affiliates.

We estimate the annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax/(benefit) rate is zero. Our actual effective tax/(benefit) rate for the three months ended September 30, 2015 was also zero. The variance from the U.S. statutory rate of 35% is primarily due to continued recorded and forecast losses that, based on present circumstances, will not result in us recording a current income tax benefit. Rather, all increases in net deferred tax assets (primarily related to net operating loss (“NOL”) carryovers net of deferred tax liability from oil and natural gas properties’ net book carrying values exceeding their corresponding tax bases) will be completely offset by increases in valuation allowances. As required by ASC Topic 740-270, Income Taxes: Interim Reporting, we forecast our tax position for the year, and may not record an additional tax benefit in an interim period unless we believe that we would be allowed to record a net deferred tax asset at the end of the year. At this time, we do not have such a belief (due to a preponderance of negative evidence as to future realizability) and accordingly reflect a current deferred tax benefit of zero. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.

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

On March 12, 2015, in connection with EGC’s issuance of the 11.0% Notes, we entered into the Promissory Note with a face value of $325 million. The Promissory Note bears interest at an annual rate of 10%, has a maturity date of October 9, 2018, and is secured by a second priority lien on certain of our assets that secure the obligations under the First Lien Credit Agreement. Interest expense on the Promissory Note amounted to approximately $8.3 million for the three months ended September 30, 2015. See Note 5 — Indebtedness for more information regarding the Promissory Note.

(10) Commitments and Contingencies

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

Performance Bonds.  As of September 30, 2015, we had $180.8 million of performance bonds outstanding relating to assets in the Gulf of Mexico. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $58.3 million of our performance bonds are lease and/or area bonds issued to the Bureau of Ocean Energy Management (“BOEM”) that assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $122.5 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and

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

(10) Commitments and Contingencies  – (continued)

facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM (which is reflected in the $58.3 million in lease and/or area bonds discussed above), and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental financial assurance and/or bonding obligations. On June 30, 2015, we sold the East Bay field, and as a result, the $566.5 million of requested supplemental financial assurance and/or bonding required by the BOEM in April 2015 was reduced by approximately $178 million.

Since our June 2015 agreements with the BOEM, we have worked towards preparing a long-term financial assurance plan that we could submit to the BOEM for approval. We have held meetings with the BOEM in furtherance of the plan’s development and, while a version of the long-term financial assurance plan could be submitted by November 15, 2015, we are currently seeking a 30-day extension to the November 15, 2015 date in order to augment the final plan in light of new information received.

In October 2015, we received information from the BOEM indicating that, following November 15, 2015, we may receive additional demands of supplemental financial assurance for amounts in addition to the $566.5 million initially sought by the BOEM in April 2015, primarily relating to certain properties that are no longer exempt from supplemental bonding as a result of co-owners losing their exemptions. We believe that a substantial portion of the additional supplemental financial assurance and/or bonding that may be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and address these potential additional liabilities. We would expect that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding.

Consequently, we expect that the BOEM will assess additional supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued after November 15, 2015 if these items are not otherwise addressed in our long-term financial assurance plan. If we are successful in obtaining the 30-day extension, we intend for our long-term financial assurance plan to address these additional financial assurance requirements for which we received information in October 2015. Please note if our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements.

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

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

(10) Commitments and Contingencies  – (continued)

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

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

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our credit facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Other.  We maintain restricted escrow funds as required by certain contractual arrangements. At September 30, 2015, our restricted cash included $21 million related to the East Bay sale which will remain restricted until our next borrowing base redetermination and approximately $6.0 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field, which will be transferred to the buyer of our interests in that field.

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

(11) Supplemental Condensed Consolidating Financial Information

In connection with issuing the 8.25% Senior Notes described in Note 5 — Indebtedness, all of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries) each of which is 100% owned by EPL (the “Guarantor Subsidiaries”), jointly and severally guaranteed the payment obligations under our 8.25% Senior Notes. The guarantees are full and unconditional, as those terms are used in Rule 3-10 of Regulation S-X, except that a Guarantor Subsidiary can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2011 Indenture. So long as other applicable provisions of the indenture are adhered to, these customary circumstances include: when a Guarantor Subsidiary is declared “unrestricted” for covenant purposes, when the requirements for legal

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

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

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

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

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

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	—			$	—			$	—
Trade accounts receivable – net			55,146				—				—				55,146
Intercompany receivables			—				127,756				(127,756	)			—
Fair value of commodity derivative instruments			1,970				—				—				1,970
Restricted cash			6,025				—				—				6,025
Prepaid expenses			1,523				—				—				1,523
Total current assets			64,664				127,756				(127,756	)			64,664
Net property and equipment			1,051,005				2,949				—				1,053,954
Restricted cash			21,008				—				—				21,008
Investment in affiliates			130,705				—				(130,705	)			—
Other assets			947				—				—				947
Total assets		$	1,268,329			$	130,705			$	(258,461	)		$	1,140,573
LIABILITIES AND STOCKHOLDER'S DEFICIT
Current liabilities:
Accounts payable		$	42,797			$	—			$	—			$	42,797
Due to EGC			190,401				—				—				190,401
Intercompany payables			127,756				—				(127,756	)			—
Accrued liabilities			71,550				—				—				71,550
Asset retirement obligations			15,839				—				—				15,839
Current maturities of long-term debt			1,684				—				—				1,684
Total current liabilities			450,027				—				(127,756	)			322,271
Long-term debt			686,018				—				—				686,018
Promissory note payable to EGC			325,000				—				—				325,000
Asset retirement obligations			196,004				—				—				196,004
Total liabilities			1,657,049				—				(127,756	)			1,529,293
Stockholder's equity (deficit):
Preferred stock			—				—				—				—
Common stock			—				—				—				—
Additional paid-in capital			1,599,341				85,479				(85,479	)			1,599,341
Retained earnings (accumulated deficit)			(1,988,061	)			45,226				(45,226	)			(1,988,061	)
Total stockholder's equity (deficit)			(388,720	)			130,705				(130,705	)			(388,720	)
Total liabilities and stockholder's equity (deficit)		$	1,268,329			$	130,705			$	(258,461	)		$	1,140,573

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

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

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

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

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

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

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

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Net cash provided by operating activities		$	15,936			$	—			$	—			$	15,936
Cash flows used in investing activities:
Capital expenditures			(13,120	)			—				—				(13,120	)
Net cash used in investing activities			(13,120	)			—				—				(13,120	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt			(1,698	)			—				—				(1,698	)
Cash restricted under revolving credit facility related to property sold			(21,008	)			—				—				(21,008	)
Advances from EGC			19,673				—				—				19,673
Net cash used in financing activities			(3,033	)			—				—				(3,033	)
Net decrease in cash and cash equivalents			(217	)			—				—				(217	)
Cash and cash equivalents at beginning of period			217				—				—				217
Cash and cash equivalents at end of period		$	—			$	—			$	—			$	—

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EPL OIL & GAS, INC.
 
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 used in investing activities:
Property acquisitions			(260	)			—				—				(260	)
Capital expenditures			(107,185	)			(3,951	)			—				(111,136	)
Other property and equipment additions			(40	)			—				—				(40	)
Net cash used in investing activities			(107,485	)			(3,951	)			—				(111,436	)
Cash flows provided by financing activities:
Advances from EGC			43,010				—				—				43,010
Net cash provided by financing activities			43,010				—				—				43,010
Net decrease in cash and cash equivalents			(5,578	)			—				—				(5,578	)
Cash and cash equivalents at beginning of period			5,601				—				—				5,601
Cash and cash equivalents at end of period		$	23			$	—			$	—			$	23

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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 2015 Annual Report.

Overview

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

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

As a result of the Merger, the future strategy of EPL is determined by Energy XXI’s Board of Directors. Our fiscal year 2016 capital budget is approximately $26 million, excluding potential capitalized general and administrative expenses. For the three months ended September 30, 2015, our capital expenditures totaled approximately $3 million, of which approximately $2 million was spent on development of core properties and $1 million on other assets. The budgeted capital is allocated to development activities, 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.

At June 30, 2015, our total proved reserves were 57.2 MMBOE of which 67% were oil and 76% were classified as proved developed. A prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserve portfolio, assuming no other changes in our development plans. The unweighted arithmetic average first-day-of-the-month prices used to determine our reserves as of June 30, 2015 were $73.88 per barrel of oil, $31.64 per barrel for NGLs and $3.11 per MMBtu for natural gas, which is significantly higher than current forward strip prices. At NYMEX forward strip pricing as of October 30, 2015, we estimate that our total proved reserve equivalent volumes as of June 30, 2015 would have been approximately 23.3% smaller compared to the results obtained using SEC pricing. Our estimated reserves as of June 30, 2015 may be further adjusted as warranted based on any changes to our long range plan, expected capital availability and drilling cost environment.

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

Known Trends and Uncertainties

Commodity Price Volatility.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil prices declined significantly during fiscal year 2015, and our ability to maintain current production levels could be impacted by continued downward pressure on oil prices. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from

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October 1, 2014 to September 30, 2015 ranged from a high of $91.01 to a low of $38.24, a decrease of 58.0%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to September 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 30, 2015, the spot market price for WTI was $45.09. The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. If we experience sustained periods of low prices for oil and natural gas, it will likely have a further material adverse effect on our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

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

Ceiling Test Write-down.  During the three months ended September 30, 2015, we recognized a ceiling test write-down of our oil and natural gas properties of $308.1 million. The write-downs did not impact our cash flows from operating activities but did increase our net loss for the quarter and stockholders’ deficit. Further ceiling test write-downs may be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows. Based on an estimated average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 months ending December 31, 2015 (reflecting an estimated price for December 1, 2015 based on current strip pricing), we presently expect to incur further impairment of $225 million to $325 million in the second fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues beyond this first fiscal quarter of 2016, we could incur further impairment to our full cost pool in fiscal 2016 and beyond based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

BOEM Supplemental Financial Assurance and/or Bonding Requirements.  In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field, and as a result, the $566.5 million of requested supplemental bonding was reduced by approximately $178 million. We currently maintain approximately $58.3 million in lease and/or area bonds issued to the BOEM and approximately $122.5 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $180.8 million, with an annual premium expense of $2.7 million.

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

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third parties that are outstanding as of September 30, 2015, we can provide no assurance that the BOEM will consider them when determining the total value of additional financial assurances and/or bonding we must provide.

Since our June 2015 agreements with the BOEM, we have worked towards preparing a long-term financial assurance plan that we could submit to the BOEM for approval. We have held meetings with the BOEM in furtherance of the plan’s development and, while a version of the long-term financial assurance plan could be submitted by November 15, 2015, we are currently seeking a 30-day extension to the November 15, 2015 date in order to augment the final plan in light of new information received.

In October 2015, we received information from the BOEM indicating that, following November 15, 2015, we may receive additional demands of supplemental financial assurance for amounts in addition to the $566.5 million initially sought by the BOEM in April 2015, primarily relating to certain properties that are no longer exempt from supplemental bonding as a result of co-owners losing their exemptions. We believe a substantial portion of the additional supplemental financial assurance and/or bonding that may be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and address these potential additional liabilities. We would expect that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding.

Consequently, as we currently evaluate the information received from the BOEM in October 2015 and after taking into account items that we expect to be able to remove from our responsibility described above, we believe that the BOEM will assess an additional $125 to $200 million of supplemental financial assurance and/or bonding requirements on us in such other letters that may be issued after November 15, 2015 if these items are not otherwise addressed in our long-term financial assurance plan. If we are successful in obtaining the 30-day extension, we intend for our long-term financial assurance plan to address these additional financial assurance requirements for which we received information in October 2015. Please note if our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements.

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

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

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In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our credit facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

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

We have contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

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

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Results of Operations

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

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

Revenue Variances

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

Our consolidated revenues decreased $105.4 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity sales prices and lower gain on derivative financial instruments. Revenue variances related to commodity prices, sales volumes and hedging activities are presented in the following table and described below.

Price and Volume Variances

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

Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $107.6 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $50.52 per barrel in the first quarter of fiscal 2016, resulting in lower revenues of $84.0 million. Average natural gas prices decreased $1.27 per Mcf in the first quarter of fiscal 2016 compared to the first quarter of fiscal 2015, resulting in lower revenues of $4.5 million. For the first quarter of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $1.14 per BOE compared to a gain of $9.69 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $19.1 million.

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Commodity prices are affected by many factors that are outside of our control, and we cannot accurately predict future commodity prices. Depressed commodity prices over an extended period of time could result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. Reductions in our capital expenditures could result in a reduction of production volumes.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes decreased 0.2 MBbls per day in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $1.0 million. Natural gas sales volumes were higher in the first quarter of fiscal 2016, increasing 13.1 MMcf per day for the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in higher revenues of $3.2 million.

Costs and Expenses and Other (Income) Expense

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

Costs and expenses decreased $70.4 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to the decrease in lease operating expense and depreciation, depletion and amortization (“DD&A”) and other factors discussed further below.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at September 30, 2015, we recognized a ceiling test impairment of our oil and natural gas properties totaling $308.1 million during the quarter ended September 30, 2015.

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

Lease operating expense decreased $30.1 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year. This decrease was primarily due to lower direct lease operating expenses stemming from declining service costs resulting from the decline in commodity prices, downward revision in estimates and decrease in demand for oil field services. Lease operating expense per BOE declined from $24.96 for the quarter ended September 30, 2014 to $10.74 for the quarter ended September 30, 2015.

DD&A expense decreased $16.1 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to a decrease in the DD&A per BOE rate of $9.01, which decreased DD&A expense by $20.3 million. This decrease was partially offset by an increase in DD&A expense of $4.2 million due to higher net production. The decrease in the DD&A rate in the first quarter of fiscal 2016 was primarily due to the reduction in our full cost pool due to the impairments of our oil and natural gas properties in prior quarterly periods of fiscal year 2015 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

Interest expense increased approximately $6.1 million in the first quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to interest on the promissory note payable to EGC.

Income Taxes

The income tax expense for the first quarter of fiscal 2016 is computed based on our estimated annual effective tax/(benefit) rate for the full fiscal year. We recorded no income tax expense (benefit) in the first quarter of fiscal 2016 compared to income tax expense of $12.8 million in the first quarter of fiscal 2015. For first quarter of fiscal 2015, our effective income tax rate was 35.9%, which excludes the impact of the goodwill impairment charge recorded during the period, which is not deductible for income tax purposes and was treated as a discrete item for purposes of computing our interim provision for income taxes. The decrease in the tax rate is primarily due to the book loss for the quarter, the forecast book loss for the year and our inability to currently record any additional net deferred tax assets due to a preponderance of negative evidence as to future realizability of these deferred tax assets. See Note 8 — Income Taxes in Notes to Consolidated Financial Statements in this Quarterly Report.

Liquidity and Capital Resources

Overview

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

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

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borrowing, or issue or extend letters of credit, that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty in determining fair market value of oil and natural gas assets which accordingly may impact our ability to continue to give the required representation. In addition, based on projected market conditions and commodity prices, we currently expect that we will not be in compliance with certain covenants under the First Lien Credit Agreement in certain future periods, including periods prior to June 30, 2016. We continue to focus on reducing our leverage and are working with our bank group on certain amendments to our First Lien Credit Agreement to address these concerns. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under the Revolving Credit Facility were to accelerate the indebtedness under the Revolving Credit Facility as a result of such defaults, such acceleration could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

Borrowings under our First Lien Credit Agreement are limited to a borrowing base based on oil and natural gas reserve values which are re-determined on a periodic basis. We and our lenders are currently in the process of our fall borrowing base redetermination, which we expect to conclude during December 2015. Given EGC’s current borrowing base at $500 million and the resulting asset coverage for the Revolving Credit Facility, we do not currently anticipate any borrowing base reductions in connection with the current borrowing base redetermination. However, it is possible if commodity prices were to decline significantly from current levels, our borrowing base under our Revolving Credit Facility may be reduced in subsequent redeterminations, 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.

As of September 30, 2015, we had total indebtedness of $1,012.7 million as described in greater detail under — Our Indebtedness and Available Credit. During October 2015, we repurchased $29.8 million in aggregate principal amount of the 8.25% Notes due 2018 in open market transactions at a total price of approximately $10.0 million. As a result, we had total indebtedness of $981.4 million net of approximately $1.5 million in debt premium as of October 31, 2015. All of our outstanding indebtedness will mature within the next three years. In addition, the maturity of certain of our and EGC’s outstanding indebtedness may be accelerated in certain situations. Pursuant to the indenture governing EGC’s 11.0% Notes, EGC will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30^th day prior to the stated maturity date of the 9.25% Senior Notes (December 15, 2017), if on such date the aggregate outstanding principal amount of all such notes exceeds $250.0 million, or (ii) on the 30^th day prior to the stated maturity date of the 8.25% Senior Notes (February 15, 2018), if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million. In addition, our revolving credit facility is scheduled to mature on April 9, 2018; however, the maturity of our revolving credit facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our ability to maintain and grow reserves and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. For example, constraints in the credit markets may increase the rates we are charged for utilizing these markets. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we will have to take certain actions described in greater detail in “Risk Factors — We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to

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

In light of current commodity prices and our substantial leverage position, EGC’s parent continues to analyze a variety of transactions and mechanisms designed to reduce debt, including the retirement or purchase of outstanding debt securities, including our outstanding debt securities, through cash purchases in open market purchases and/or exchanges for equity or other securities of the Company through privately negotiated transactions or otherwise and opportunistic acquisitions. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors and there can be no assurance that we will take any of these actions.

Our Indebtedness and Available Credit

Revolving Credit Sub-Facility.  The First Lien Credit Agreement, as amended, has a maximum facility amount and borrowing base for EGC of $500 million, of which such amount $150 million is the borrowing base for EPL (the “Revolving Credit Sub-Facility”). As of September 30, 2015, we have fully utilized amounts available under our Revolving Credit Sub-Facility. The maturity date of the First Lien Credit Agreement is April 9, 2018, provided that certain conditions are met; however, the maturity of the revolving credit facility will accelerate if EGC’s 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. Our Revolving Credit Facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 5% of the overall commitment amount.

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

Since required lender consent to the specific terms of the transaction with respect to the sale of the East Bay field had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required EPL to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC.

8.25% Senior Notes.  The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount issued under an indenture dated February 14, 2011 (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

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guaranteed, jointly and severally, on an unsecured senior basis initially by each of our existing direct and indirect domestic subsidiaries (other than immaterial subsidiaries). The 8.25% Senior Notes will mature on February 15, 2018. As of September 30, 2015, we were in compliance with all of the covenants under the 2011 Indenture.

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

For more information regarding our outstanding indebtedness, see Note 5 — Indebtedness in the Notes to Consolidated Financial Statements contained in this Quarterly Report.

BOEM Bonding Requirements

As of September 30, 2015, we had $180.8 million of performance bonds outstanding relating to assets in the Gulf of Mexico. As a lessee and operator of oil and natural gas leases on the federal OCS, approximately $58.3 million of our performance bonds are lease and/or area bonds issued to the BOEM that assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $122.5 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Our total supplemental bonding results in an annual premium expense of approximately $2.7 million. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM (which is reflected in the $58.3 million in lease and/or area bonds discussed above), and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $566.5 million of requested supplemental bonding was reduced by approximately $178 million.

Since our June 2015 agreements with the BOEM, we have worked towards preparing a long-term financial assurance plan that we could submit to the BOEM for approval. We have held meetings with the BOEM in furtherance of the plan’s development and, while a version of the long-term financial assurance plan could be submitted by November 15, 2015, we are currently seeking a 30-day extension to the November 15, 2015 date in order to augment the final plan in light of new information received.

In October 2015, we received information from the BOEM indicating that, following November 15, 2015, we may receive additional demands of supplemental financial assurance for amounts in addition to the $566.5 million initially sought by the BOEM in April 2015, primarily relating to certain properties that are no longer exempt from supplemental bonding as a result of co-owners losing their exemptions. We believe a substantial portion of the additional supplemental financial assurance and/or bonding that may be sought by the BOEM may relate to circumstances that could eventually be removed from our responsibility (in terms of providing added assurance or bonding), including, for example, lease interests of co-lessees, leases that have since been divested by us, and leases where we are not the permitted operator and no drilling of wells has occurred. Our request for a 30-day extension from the November 15, 2015 date for submittal of the long-term financial assurance plan is in part to give us time to evaluate and address these potential additional liabilities. We would expect that most, if not all, of our co-lessees with the remaining working interest in such lease interests will provide their share of the bonding.

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

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items are not otherwise addressed in our long-term financial assurance plan. If we are successful in obtaining the 30-day extension, we intend for our long-term financial assurance plan to address these additional financial assurance requirements for which we received information in October 2015. Please note if our co-lessees and us are unable to agree on allocation of supplemental financial assurance and/or bonding amounts for such specified leases and present such agreed upon allocations to the BOEM for approval, the BOEM may direct supplemental financial assurance and/or bonding amounts for 100% of the lease interests to us, which would substantially increase the supplemental financial assurance and/or bonding requirements.

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

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

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the bureau, the BOEM is actively seeking to bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements, including the directives issued by the BOEM in April 2015 and June 2015, any other future directives, or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our subsidiaries’ properties could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide cash collateral or letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our credit facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material effect on our business, prospects, results of operations, financial condition, and liquidity.

Capital Expenditures

Our initial fiscal year 2016 capital budget is expected to be approximately $26 million. For the three months ended September 30, 2015, our capital expenditures totaled approximately $3 million, of which approximately $2 million was spent on development of core properties and $1 million on other assets. The budgeted capital is allocated to development activities, 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 intend to fund our capital expenditures and contractual commitments, including settlement of derivative contracts, with cash flows from operations and borrowings and equity investments from EGC. If oil and natural gas prices remain at current levels or continue to decline, we may be required to reduce our capital expenditure budget for fiscal year 2016 and future years, which in turn may affect our liquidity and results of operations in future periods. If our cash flows from operations and

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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. There is no guarantee that we can access debt and equity capital markets or sell non-core assets at attractive terms. Our capital expenditures and the scope of our drilling activities for fiscal year 2016 may change as a result of several factors, including, but not limited to, changes in oil and natural gas sales prices, costs of drilling and completion operations and drilling results and available funding from EGC.

Disposition

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

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

Cash Flows

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

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

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

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

Net cash used in financing activities for the first quarter of fiscal 2016 primarily reflects $21.0 million in cash restricted related to the sale of the East Bay field, offset by advances from EGC. Net cash provided by financing activities for the first quarter of fiscal year 2015 reflects $43.0 million in advances from EGC.

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

Contractual Obligations

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

Critical Accounting Policies

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

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Recent Accounting Pronouncements

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

General

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

We are exposed to a variety of market risks including commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at September 30, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.

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

Commodity Price Risk

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

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. We have incurred debt under the borrowing base of our Revolving Credit Sub-Facility. This borrowing base is subject to periodic redetermination based in part on changing expectations of future prices. Recently, commodity prices have deteriorated materially. Given EGC’s current borrowing base at $500 million and the resulting asset coverage for the Revolving Credit Facility, we do not currently anticipate any borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, the borrowing base under the Revolving Credit Facility may be further reduced, which would require EGC and us to repay that portion, if any, of our outstanding indebtedness under the facility in excess of the new borrowing base. The energy markets have historically been very volatile, and there can be no assurance that crude oil and natural gas prices will improve.

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

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

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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, 2015, our crude oil contracts outstanding were in an asset position of $1.5 million. A 10% increase in crude oil prices would reduce the fair value by approximately $0.8 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $1.7 million. At September 30, 2015, our natural gas contract outstanding was in an asset position of $0.5 million. A 10% increase in natural gas prices would reduce the fair value by approximately $0.1 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $0.1 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2015.

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

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

Interest Rate Risk

Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our Revolving Credit Sub-Facility. As of September 30, 2015, total debt included $150.0 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 15% of our total debt outstanding as of September 30, 2015. A 10% change in floating interest rates on period-end floating debt balances would change quarterly interest expense by approximately $7,238. We currently have no interest rate hedge positions in place to reduce our 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.

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2015, Energy XXI’s board of directors began the process of designing and implementing additional controls and procedures in response to a material weakness in its control environment identified during the preparation of its financial statements for the fiscal year ended June 30, 2015, including, but not limited to, strengthening Energy XXI’s vendor procurement procedures to

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

Other than changes related to the items noted above, there was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II — OTHER INFORMATION

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

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 2015 Annual Report. There have been no material changes in the risk factors set forth in our 2015 Annual Report.

None

None

Not applicable

None

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 13, 2015		By: /s/ Rick D. Fox Rick D. Fox Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

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INDEX TO EXHIBITS

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

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Exhibit Number

Exhibit Description

Incorporated by Reference Form

SEC File Number

Exhibit

Filing Date

Filed/ Furnished Herewith

101.INS*

XBRL Instance Document

X

101.SCH*

XBRL Taxonomy Extension Schema Document

X

101.CAL*

XBRL Taxonomy Extension Calculation Linkbase Document

X

101.LAB*

XBRL Taxonomy Extension Label Linkbase Document

X

101.DEF*

XBRL Taxonomy Extension Definition Linkbase Document

X

101.PRE*

XBRL Taxonomy Extension Presentation Linkbase Document

X