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

 

Form 10-Q

 

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

For the quarterly period ended December 31, 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			30
Item 3. Quantitative and Qualitative Disclosures about Market Risk			45
Item 4. Controls and Procedures			46
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			47
Item 1A. Risk Factors			47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			51
Item 3. Defaults Upon Senior Securities			51
Item 4. Mine Safety Disclosures			51
Item 5. Other Information			51
Item 6. Exhibits			51
SIGNATURES			52
EXHIBIT INDEX			53

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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 Annual Report on 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)

		December 31, 2015				June 30, 2015
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	217
Trade accounts receivable – net			42,480				71,323
Derivative financial instruments			—				888
Restricted cash			6,025				6,024
Prepaid expenses			2,631				1,831
Total current assets			51,136				80,283
Property and equipment, net – full cost method of accounting, including $45.5 million and $435.4 million of unevaluated properties not being amortized at December 31, 2015 and June 30, 2015, respectively			481,426				1,415,025
Restricted cash			30,008				—
Other assets and debt issuance costs, net of accumulated amortization			1,036				1,039
Total assets		$	563,606			$	1,496,347
LIABILITIES AND STOCKHOLDER’S DEFICIT
Current liabilities:
Accounts payable		$	33,076			$	24,548
Due to EGC			202,767				170,728
Accrued liabilities			94,567				95,981
Asset retirement obligations			29,077				38,056
Derivative financial instruments			—				1,057
Current maturities of long-term debt			—				3,364
Total current liabilities			359,487				333,734
Long-term debt, less current maturities			651,462				689,459
Promissory note payable to EGC			325,000				325,000
Asset retirement obligations			160,909				202,306
Total liabilities			1,496,858				1,550,499
Commitments and contingencies (Note 11)
Stockholder’s deficit:
Preferred stock, par value $0.001 per share. Authorized 1,000,000 shares; no shares issued and outstanding at December 31, 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 December 31, 2015 and June 30, 2015			—				—
Additional paid-in capital			1,599,341				1,599,341
Accumulated deficit			(2,532,593	)			(1,653,493	)
Total stockholder’s deficit			(933,252	)			(54,152	)
Total liabilities and stockholder’s deficit		$	563,606			$	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 December 31,								Six Months Ended December 31,
		2015				2014				2015				2014
Revenues
Oil sales		$	54,408			$	120,828			$	127,780			$	279,144
Natural gas sales			8,256				12,548				20,874				26,502
Gain on derivative financial instruments			906				22,262				3,684				44,119
Total Revenues			63,570				155,638				152,338				349,765
Costs and expenses
Lease operating			30,889				55,304				57,042				111,604
Transportation			664				1,149				1,387				1,774
Depreciation, depletion and amortization			62,333				88,547				119,993				162,292
Accretion of asset retirement obligations			6,317				6,098				13,058				12,279
Impairment of oil and natural gas properties			504,772				690,312				812,850				690,312
Goodwill impairment			—				—				—				329,293
General and administrative expense			9,978				6,810				17,922				14,852
Taxes, other than on earnings			39				1,944				(896	)			4,472
Other			—				—				—				21
Total costs and expenses			614,992				850,164				1,021,356				1,326,899
Operating Loss			(551,422	)			(694,526	)			(869,018	)			(977,134	)
Other income (expense):
Other income, net			2,393				4				2,405				4
Gain on early extinguishment of debt			21,269				—				21,269				—
Interest expense			(16,772	)			(10,947	)			(33,756	)			(21,848	)
Total other income (expense), net			6,890				(10,943	)			(10,082	)			(21,844	)
Loss before income taxes			(544,532	)			(705,469	)			(879,100	)			(998,978	)
Income tax benefit			—				(250,857	)			—				(238,010	)
Net loss		$	(544,532	)		$	(454,612	)		$	(879,100	)		$	(760,968	)

 
 
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)

		Six Months Ended December 31,
		2015				2014
Cash flows from operating activities:
Net loss		$	(879,100	)		$	(760,968	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			119,993				162,292
Accretion of asset retirement obligations			13,058				12,279
Gain on early extinguishment of debt			(21,269	)			—
Change in fair value of derivative financial instruments			(1,573	)			(14,657	)
Deferred income taxes			—				(238,010	)
Impairment of oil and natural gas properties			812,850				690,312
Goodwill impairment			—				329,293
Amortization of premium and debt issuance costs			(6,532	)			(5,104	)
Changes in operating assets and liabilities:
Trade accounts receivable			26,776				9,721
Prepaid expenses and other assets			(800	)			16,762
Accounts payable and accrued liabilities			12,687				(70,981	)
Asset retirement obligation settlements			(48,627	)			(32,038	)
Net cash provided by operating activities			27,463				98,901
Cash flows used in investing activities:
Property acquisitions			—				(350	)
Capital expenditures			(16,122	)			(239,090	)
Other property and equipment additions			—				(58	)
Net cash used in investing activities			(16,122	)			(239,498	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt			(3,395	)			—
Cash restricted under revolving credit facility			(30,008	)			—
Advances from EGC			22,034				135,480
Debt issuance costs			(189	)			—
Net cash provided by (used in) financing activities			(11,558	)			135,480
Net decrease in cash and cash equivalents			(217	)			(5,117	)
Cash and cash equivalents at beginning of period			217				5,601
Cash and cash equivalents at end of period		$	—			$	484
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Non-cash investing information:
Changes in capital expenditures accrued in accounts payable		$	(2,071	)		$	(49,814	)
Changes in asset retirement obligations			(14,807	)			5,212
Cash paid during the period for:
Interest		$	24,679			$	26,948

 
 
See accompanying Notes to Consolidated Financial Statements.

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

Note 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 interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

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

Note 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. Our early adoption of ASU 2014-15 during the quarter ended December 31, 2015 impacted our disclosures but had no effect on our consolidated financial position, results of operations or cash flows.

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 November 2015, the FASB issued ASU. No. 2015-17, Balance Sheet Classification of Deferred Taxes (“ASU 2015-17”). ASU 2015-17 simplifies the presentation of deferred taxes on the balance sheet by requiring classification of all deferred tax items as noncurrent including valuation allowances by jurisdiction. The ASU is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is permitted as of the beginning of any interim or annual reporting period. Our early adoption of ASU 2015-17 during the quarter ended December 31, 2015 had no effect on our consolidated financial position, results of operations or cash flows other than presentation.

Note 2 — Liquidity and Capital Resources

Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. However, future cash flows are subject to a number of variables, and are highly dependent on the prices we receive for oil and natural gas. Oil and natural gas prices declined severely during fiscal year 2015 and have declined even further through fiscal 2016 to date. The price of WTI crude oil per barrel dropped below $27.00 per barrel in January 2016 for the first time in twelve years. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices will have a material and adverse effect on our liquidity position.

As of December 31, 2015, we had $150 million in borrowings outstanding under the second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility” or “Revolver”), to which we are a party with EGC, and we were in compliance with our financial covenants; however, based on current market conditions and depressed commodity prices, if Energy XXI is unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016. In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency and we must remain in compliance with the financial ratios in the Revolving Credit Facility. 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

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

Note 2 — Liquidity and Capital Resources  – (continued)

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.

Energy XXI is evaluating various alternatives with respect to the Revolving Credit Facility, but there is no certainty that it will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we may be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. 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 would cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI’s other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we will not have sufficient liquidity to repay all of our outstanding indebtedness.

EGC may face other impediments to accessing available borrowing capacity under the Revolving Credit Facility. Borrowings under the First Lien Credit Agreement are limited to a borrowing base based on oil and natural gas reserve values which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we, EGC and our lenders completed our fall borrowing base redetermination with no changes to the existing borrowing base available to EPL of $150 million (the “Revolving Credit EPL Sub-Facility), although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. As of December 31, 2015, we had fully utilized amounts available under the Revolving Credit EPL Sub-Facility. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit EPL Sub-Facility borrowing base and commitment amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness in excess of any reduced borrowing base.

In addition, in response to commodity price declines, our fiscal year 2016 capital budget was substantially reduced compared to actual capital expenditures in fiscal year 2015. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization. The curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

We may experience a further strain on our liquidity if the BOEM requires us to provide additional bonding as a means to assure our decommissioning obligations, such as the plugging of wells, the removal of platforms and other facilities, the abandonment of pipelines and the clearing of the seafloor of obstructions, or if the surety companies providing such bonds on our behalf require us to provide additional cash collateral for

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

Note 2 — Liquidity and Capital Resources  – (continued)

such bonds. Any further expense in providing additional bonds or restrictions on our cash to collateralize existing bonds or new bonds would further reduce our liquidity.

Beginning on January 11, 2016, Energy XXI’s common stock has generally traded on NASDAQ at less than $1.00 per share. Due to certain NASDAQ requirements, there is no assurance that the price of Energy XXI’s common stock will comply with the requirements for continued listing of its shares on NASDAQ. A delisting of Energy XXI’s common stock could constitute a “fundamental change” under the terms of its $400 million aggregate principal amount of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). If such a fundamental change occurs at any time prior to the maturity of the 3.0% Senior Convertible Notes, each holder of such notes shall have the right to require Energy XXI to repurchase all or part of such holder’s 3.0% Senior Convertible Notes in accordance with the terms of the 3.0% Senior Convertible Notes. We cannot assure that Energy XXI would have adequate liquidity to fund such a repurchase given its severe liquidity constraints. Such acceleration would cause a cross-default or cross-acceleration of all of Energy XXI’s other outstanding indebtedness, including our 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 will not have sufficient liquidity to repay all of our outstanding indebtedness.

As described below under Note 6 — Indebtedness, we had total indebtedness of $976.5 million as of December 31, 2015, and taking into account bond repurchases subsequent to December 31, 2015 of approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes due 2018 (the “8.25% Senior Notes”), we had total indebtedness of $697.1 million as of February 15, 2016. All of our outstanding indebtedness will mature within the next three years. In addition, the Revolving Credit Facility is scheduled to mature on April 9, 2018; however, the maturity of the Revolving Credit Facility will accelerate if EGC’s 9.25% Senior Notes due 2017 (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. All of the factors described above have placed considerable pressure on our ability to pay the principal and interest on our long-term debt, satisfy our other liabilities, continue our development activities to maintain and grow reserves and our ability to refinance our debt as it becomes due.

As a result of the commodity price decline and the Company’s substantial debt burden, absent a material improvement in oil and gas prices or a refinancing or restructuring of our debt obligations or other improvement in liquidity, the Company believes forecasted cash and expected available credit capacity will not be sufficient to meet commitments as they come due for the next twelve months. This raises substantial doubt regarding the Company’s ability to continue as a going concern.

In February 2016, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P as a legal advisor to advise its management and Board of Directors (the “Board”), EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. We cannot assure that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Energy XXI is also focused on long-term recurring cost reductions and the identification of non-core assets for potential sale. We cannot assure that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows.

As a result of the commodity price decline, we will continue to evaluate our ability to make the debt payments as they become due and to meet the additional supplemental bonding requirements of the BOEM and our surety companies’ requirements to provide additional cash collateral for such existing and future bonds in light of our liquidity constraints. On February 16, 2016, we elected to enter into the 30-day grace

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

Note 2 — Liquidity and Capital Resources  – (continued)

period under the terms of the indenture governing our outstanding 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing the 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit EPL Sub-Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations.

Absent a material improvement in oil and gas prices or a refinancing or some restructuring of our debt obligations or other improvement in liquidity, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of recorded assets or the amounts and classification of liabilities.

Note 3 — 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 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

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Note 3 — Pushdown Accounting and Goodwill  – (continued)

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.

Note 4 — Property and Equipment

The following table summarizes our property and equipment.

		December 31, 2015				June 30, 2015
		(In thousands)
Proved oil and natural gas properties		$	3,385,252			$	2,993,012
Unevaluated oil and natural gas properties			45,549				435,429
Other			—				3,116
Less: accumulated depreciation, depletion, amortization and impairment			(2,949,375	)			(2,016,532	)
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment		$	481,426			$	1,415,025

At December 31, 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

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Note 4 — Property and Equipment  – (continued)

than four years. In the six months ended December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

Due to the depressed commodity prices and our lack of capital resources to develop our properties, we believe that all of our proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling.

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. For the three and six months ended December 31, 2015, our ceiling test computation resulted in impairments of our oil and natural gas properties of $504.8 million and $812.9 million, respectively. If the current low commodity price environment or downward trend in oil prices continues, we will 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.

Note 5 — Asset Retirement Obligations

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

		Six Months Ended December 31, 2015
		(in thousands)
Beginning of period total		$	240,362
Accretion expense			13,058
Liabilities incurred			3,457
Revisions*			(18,264	)
Liabilities settled			(48,627	)
End of period total			189,986
Less: End of period, current portion			(29,077	)
End of period, noncurrent portion		$	160,909

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness

The following table sets forth our indebtedness.

		December 31, 2015				June 30, 2015
		(In thousands)
8.25% Senior Notes due 2018		$	480,244			$	510,000
Debt premium on 8.25% Senior Notes due 2018			21,218				29,459
Revolving Credit EPL Sub-Facility			150,000				150,000
Derivative instruments premium financing			—				3,364
Total debt			651,462				692,823
Less current maturities			—				(3,364	)
Long term debt			651,462				689,459
Promissory note payable to EGC			325,000				325,000
Noncurrent portion of indebtedness		$	976,462			$	1,014,459

During October 2015, we repurchased $29.8 million in aggregate principal amount of the 8.25% Senior Notes in open market transactions at a total price of approximately $10.0 million, and we recorded a gain on this repurchase of approximately $21.3 million, including the amount of associated unamortized premium, during the three months ended December 31, 2015. The repurchased notes were cancelled. Subsequent to December 31, 2015, we repurchased approximately $266.6 million in aggregate principal amount (carrying value of approximately $279.4 million) of our 8.25% Senior Notes in open market transactions at a total price of approximately $11.4 million, including accrued interest of $10.4 million, reducing our total indebtedness to approximately $697.1 million as of February 15, 2016. See below for further discussion of our 8.25% Senior Notes.

Revolving Credit EPL Sub-Facility

The Revolving Credit Facility underwent its Twelfth Amendment to the First Lien Credit Agreement on November 30, 2015 (the “Twelfth Amendment”) and its Eleventh Amendment and Waiver to the First Lien Credit Agreement was on July 31, 2015 (the “Eleventh Amendment”). The Revolving Credit Facility, as amended, has a maximum facility amount and borrowing base of $500 million, of which such amount $150 million is the borrowing base under the sub-facility established for EPL, although we were required to maintain restricted cash of $30 million with respect to amounts outstanding under the Revolving Credit EPL Sub-Facility. These respective borrowing bases were set in accordance with the regular annual process for determination of the borrowing bases and the borrowing bases are to remain in effect until the next redetermination thereof under the terms of the First Lien Credit Agreement. Borrowings under the First Lien Credit Agreement are also limited to a borrowing base based on oil and natural gas reserve values, which are redetermined on a periodic basis. During the quarter ended December 31, 2015, we, EGC and the lenders completed the fall borrowing base redetermination with no changes to the existing borrowing base at $500 million, and the lenders temporarily relaxed the requirements of certain financial covenants under the Twelfth Amendment as described below. 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% 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 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. If we experience the continuation of low oil and natural gas prices, or if they decline even further, we anticipate that our Revolving Credit Facility borrowing base and commitment

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Note 6 — Indebtedness  – (continued)

amounts will likely be reduced in the spring of 2016 as part of our next borrowing base redetermination, which would require us to repay any outstanding indebtedness in excess of any reduced borrowing base.

The Revolving Credit Facility 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 redetermined on a periodic basis. 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 shall have 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 shall have become guarantors of the EGC indebtedness under the First Lien Credit Agreement) at 85%. Additionally, as a result of the Twelfth Amendment, we are required to maintain $30 million of restricted cash in an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement.

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%.

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 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 net secured leverage ratio of no more than 3.75 to 1.0 beginning with the fiscal quarter ending March 31, 2017. If the 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 4.75 to 1.0 as of the end of each fiscal quarter beginning with the fiscal quarter ending March 31, 2016, increasing to 5.25 to 1.0 starting June 30, 2016 and decreasing to 5.00 to 1.0 beginning June 30, 2017 and thereafter, and (c) a minimum current ratio of no less than 1.0 to 1.0.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 6 — Indebtedness  – (continued)

Additionally, the following changes became effective upon the execution of the Twelfth Amendment:

As of December 31, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, and we were in compliance with all covenants thereunder. Due to current market conditions and depressed commodity prices, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and Board, EGC and EPL regarding potential strategic alternatives to address the Company’s liquidity concerns and high debt levels. Based on current market conditions and depressed commodity prices, if it is unable to execute on one of the strategic alternatives being evaluated and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio under our Revolving Credit Facility for the quarter ending March 31, 2016. Due to our election on February 16, 2016 to enter into the 30-day grace period for making interest payment under the terms of the indenture governing our outstanding 8.25% Senior Notes, certain restrictions, as fully described below under the caption 8.25% Senior Notes Due 2018, have been placed on the Company. In addition, as part of our quarterly compliance certificates required under the Revolving Credit Facility, we must make certain representations, including representations about our solvency, and we must remain in compliance with the financial ratios in the Revolving Credit Facility. 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.

Energy XXI is evaluating various alternatives with respect to the Revolving Credit Facility, but there is no certainty that it will be able to implement any alternatives or otherwise resolve our covenant issues. If the lenders under the Revolving Credit Facility are unwilling to provide us with the covenant flexibility we seek, and we are unable to comply with those covenants, we will be forced to repay or refinance amounts then outstanding under the Revolving Credit Facility, and there is no assurance that we will reach an agreement with our lenders on any such amendment or waiver. 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 would cause a cross-default or cross-acceleration of all of our, EGC and Energy XXI’s other

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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Note 6 — Indebtedness  – (continued)

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 will 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 EPL 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 due 2018

The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount ($501.5 million carrying value at December 31, 2015) of our 8.25% senior notes due 2018 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%.

On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets.

The election to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes constitutes a default; however, it does not constitute an Event of Default under the indenture governing the 8.25% Senior Notes or the Revolving Credit Facility. As a result of this default, certain restrictions have been placed on the Company, including but not limited to, its ability to incur additional indebtedness, draw on the Revolving Credit EPL Sub-Facility and issue additional letters of credit. The Company has 30 days to cure the default by making the required interest payment that was due on February 16, 2016. Alternatively, the Company may restructure the debt with its creditors. On March 17, 2016, if the interest payment default is not cured, the default would be considered an Event of Default and the trustee or the holders of at least 25% in aggregate principal amount of then outstanding 8.25% Senior Notes may declare the principal and accrued interest for all outstanding 8.25% Senior Notes due and payable immediately. An Event of Default would also trigger cross defaults in the Company’s other debt obligations. An Event of Default would have a material adverse effect on the Company’s liquidity, financial condition and results of operations. Please see Note 2 — Liquidity and Capital Resources for more information.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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Note 6 — Indebtedness  – (continued)

Derivative Instruments Premium Financing

We have historically financed premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit EPL Sub-Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit EPL 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 December 31, 2015, we had no outstanding derivative instruments premium financing.

Interest Expense

For the three and six months ended December 31, 2015 and 2014, interest expense consisted of the following:

		Three Months Ended December 31,								Six Months Ended December 31,
		2015				2014				2015				2014
		(In thousands)								(In thousands)
8.25% senior notes due 2018		$	10,130			$	10,519			$	20,649			$	21,038
Amortization of fair value premium – 8.25% senior notes			(3,282	)			(2,570	)			(6,723	)			(5,104	)
Revolving credit EPL sub-facility			1,460				2,998				2,950				5,959
Promissory note payable to EGC			8,305				—				16,611				—
Derivative instruments premium financing and other			159				—				269				(45	)
		$	16,772			$	10,947			$	33,756			$	21,848

Note 7 — Derivative Financial Instruments

We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use various instruments including financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from changes in fair value of outstanding derivative financial instruments and from the settlement of 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. We had no derivative instruments outstanding at December 31, 2015.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 7 — Derivative Financial Instruments  – (continued)

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

		Three Months Ended December 31,								Six Months Ended December 31,
Gain (loss) on derivative financial instruments		2015				2014				2015				2014
Cash settlements, net of purchased put premium amortization		$	1,397			$	23,091			$	2,111			$	24,903
Proceeds from monetizations			—				4,559				—				4,559
Change in fair value			(491	)			(5,388	)			1,573				14,657
Total gain on derivative financial instruments		$	906			$	22,262			$	3,684			$	44,119

Note — 8 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 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 7 — Derivative Financial Instruments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note — 8 Fair Value Measurements  – (continued)

During the three and six months ended December 31, 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.

		December 31, 2015				June 30, 2015
		(in thousands)
Assets
Derivative financial instruments
Current		$	—			$	888
Total derivative financial instruments subject to enforceable netting agreement			—				888
Gross amounts offset in consolidated balance sheets			—				—
Net amounts presented in consolidated balance sheets		$	—			$	888
Liabilities
Derivative financial instruments
Current		$	—			$	1,057
Total derivative financial instruments subject to enforceable netting agreement			—				1,057
Gross amounts offset in consolidated balance sheets			—				—
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.

		December 31, 2015								June 30, 2015
		(In thousands)
		Carrying Value				Estimated Fair Value				Carrying Value				Estimated Fair Value
8.25% senior notes		$	501,462			$	135,813			$	539,459			$	306,000
Revolving credit EPL sub-facility			150,000				150,000				150,000				150,000
Promissory note payable to EGC			325,000				325,000				325,000				325,000
Total		$	976,462			$	610,813			$	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 December 31, 2015 is not material.

Note 9 — 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

Note 9 — Income Taxes  – (continued)

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 and six months ended December 31, 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.

Note 10 — 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 and six months ended December 31, 2015 was approximately $8.9 million and $18.2 million, respectively, of which approximately $7.5 million and $15.0 million, respectively, is included in general and administrative expense. Cost of these services for the three and six months ended December 31, 2014 was approximately $5.8 and $9.8 million, respectively, of which approximately $5.4 million and $9.1 million, respectively, 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. For the three and six months ended December 31, 2015, interest expense on the Promissory Note amounted to approximately $8.3 million and $16.6 million, respectively. See Note 6 — Indebtedness for more information regarding the Promissory Note.

Note 11 — 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 December 31, 2015, we had $189.7 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 $67.2 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 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 facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental

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

Note 11 — Commitments and Contingencies  – (continued)

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 and December 2015, we reached agreements with the BOEM with respect to which we provided $54.7 million and $8.9 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $67.2 million in lease and/or area bonds discussed above). 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.

In October 2015, we received information from the BOEM indicating that we could 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 were no longer exempt from supplemental bonding as a result of co-lessees losing their exemptions. However, we believe that a substantial portion of the additional supplemental financial assurance and/or bonding that could 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. 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 but we can provide no assurance that such cooperation by these co-lessees will occur.

Since we received the additional information from the BOEM in October 2015, we have had a series of discussions and exchanges of information with the BOEM on the long-term financial assurance plan, culminating most recently in our submittal of an updated version of the long-term financial assurance plan to the BOEM for approval on February 2, 2016. The long-term plan calls for a series of actions by us during various dates in 2016, including by June 1, 2016 and September 1, 2016, which actions are designed to address the supplemental financial assurance liabilities initially identified by the BOEM, as such liabilities are further modified by the BOEM based on information we provide and our performance under the plan. This long-term plan requires approval by the BOEM in order for us to proceed with addressing these supplemental financial assurance liabilities. While we believe that the long-term financial assurance plan is close to being approved by the BOEM, we can provide no assurance as to a certain date by which the long-term plan will be approved or that the BOEM will not have further revisions to our proposal.

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. 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 later if those items are not addressed in our plan.

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)

Note 11 — 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 Revolving Credit EPL Sub-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 Revolving Credit EPL Sub-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, cancelled or otherwise impose monetary penalties, and one or more of such actions 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 December 31, 2015, our restricted cash included $30 million related to the First Lien Credit Agreement 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.

Note 12 — Supplemental Condensed Consolidating Financial Information

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

Note 12 — 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 December 31, 2015
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	—			$	—			$	—			$	—
Trade accounts receivable – net			42,480				—				—				42,480
Intercompany receivables			—				127,756				(127,756	)			—
Restricted cash			6,025				—				—				6,025
Prepaid expenses			2,631				—				—				2,631
Total current assets			51,136				127,756				(127,756	)			51,136
Property and equipment, net			478,477				2,949				—				481,426
Restricted cash			30,008				—				—				30,008
Investment in affiliates			130,705				—				(130,705	)			—
Other assets and debt issuance costs, net of accumulated amortization			1,036				—				—				1,036
Total assets		$	691,362			$	130,705			$	(258,461	)		$	563,606
LIABILITIES AND STOCKHOLDER’S DEFICIT
Current liabilities:
Accounts payable		$	33,076			$	—			$	—			$	33,076
Due to EGC			202,767				—				—				202,767
Intercompany payables			127,756				—				(127,756	)			—
Accrued liabilities			94,567				—				—				94,567
Asset retirement obligations			29,077				—				—				29,077
Total current liabilities			487,243				—				(127,756	)			359,487
Long-term debt			651,462				—				—				651,462
Promissory note payable to EGC			325,000				—				—				325,000
Asset retirement obligations			160,909				—				—				160,909
Total liabilities			1,624,614				—				(127,756	)			1,496,858
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)			(2,532,593	)			45,226				(45,226	)			(2,532,593	)
Total stockholder’s equity (deficit)			(933,252	)			130,705				(130,705	)			(933,252	)
Total liabilities and stockholder’s equity (deficit)		$	691,362			$	130,705			$	(258,461	)		$	563,606

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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
Property and equipment, net			1,412,076				2,949				—				1,415,025
Investment in affiliates			130,705				—				(130,705	)			—
Other assets and debt issuance costs, net of accumulated amortization			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 December 31, 2015
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues
Oil sales		$	54,408			$	—			$	—			$	54,408
Natural gas sales			8,256				—				—				8,256
Gain on derivative instruments			906				—				—				906
Total revenues			63,570				—				—				63,570
Costs and expenses
Lease operating			30,889				—				—				30,889
Transportation			664				—				—				664
Depreciation, depletion and amortization			62,333				—				—				62,333
Accretion of asset retirement obligations			6,317				—				—				6,317
Impairment of oil and natural gas properties			504,772				—				—				504,772
General and administrative			9,978				—				—				9,978
Taxes, other than on earnings			39				—				—				39
Total costs and expenses			614,992				—				—				614,992
Operating loss			(551,422	)			—				—				(551,422	)
Other income (expense):
Other income, net			2,393				—				—				2,393
Gain on early extinguishment of debt			21,269				—				—				21,269
Interest expense			(16,772	)			—				—				(16,772	)
Total other income, net			6,890				—				—				6,890
Loss before income taxes			(544,532	)			—				—				(544,532	)
Income tax expense			—				—				—				—
Net loss		$	(544,532	)		$	—			$	—			$	(544,532	)

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EPL OIL & GAS, INC.
 
Supplemental Condensed Consolidating Statement of Operations
Three Months Ended December 31, 2014
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues
Oil sales		$	109,070			$	11,758			$	—			$	120,828
Natural gas sales			12,499				49				—				12,548
Gain on derivative instruments			22,262				—				—				22,262
Total revenues			143,831				11,807				—				155,638
Costs and expenses
Lease operating			50,044				5,260				—				55,304
Transportation			1,148				1				—				1,149
Depreciation, depletion and amortization			82,382				6,165				—				88,547
Accretion of asset retirement obligations			4,910				1,188				—				6,098
Impairment of oil and natural gas properties			690,312				—				—				690,312
General and administrative			6,810				—				—				6,810
Taxes, other than on earnings			494				1,450				—				1,944
Total costs and expenses			836,100				14,064				—				850,164
Operating loss			(692,269	)			(2,257	)			—				(694,526	)
Other income (expense):
Other income, net			4				—				—				4
Interest expense			(10,947	)			—				—				(10,947	)
Income from equity investments			(1,424	)			—				1,424				—
Total other expense, net			(12,367	)			—				1,424				(10,943	)
Loss before income taxes			(704,636	)			(2,257	)			1,424				(705,469	)
Income tax benefit			(250,024	)			(833	)			—				(250,857	)
Net loss		$	(454,612	)		$	(1,424	)		$	1,424			$	(454,612	)

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EPL OIL & GAS, INC.
 
Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2015
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues
Oil sales		$	127,780			$	—			$	—			$	127,780
Natural gas sales			20,874				—				—				20,874
Gain on derivative instruments			3,684				—				—				3,684
Total revenues			152,338				—				—				152,338
Costs and expenses
Lease operating			57,042				—				—				57,042
Transportation			1,387				—				—				1,387
Depreciation, depletion and amortization			119,993				—				—				119,993
Accretion of asset retirement obligations			13,058				—				—				13,058
Impairment of oil and natural gas properties			812,850				—				—				812,850
General and administrative			17,922				—				—				17,922
Taxes, other than on earnings			(896	)			—				—				(896	)
Total costs and expenses			1,021,356				—				—				1,021,356
Operating loss			(869,018	)			—				—				(869,018	)
Other income (expense):
Other income, net			2,405				—				—				2,405
Gain on early extinguishment of debt			21,269				—				—				21,269
Interest expense			(33,756	)			—				—				(33,756	)
Total other expense, net			(10,082	)			—				—				(10,082	)
Loss before income taxes			(879,100	)			—				—				(879,100	)
Income tax expense			—				—				—				—
Net loss		$	(879,100	)		$	—			$	—			$	(879,100	)

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EPL OIL & GAS, INC.
 
Supplemental Condensed Consolidating Statement of Operations
Six Months Ended December 31, 2014
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues
Oil sales		$	249,785			$	29,359			$	—			$	279,144
Natural gas sales			26,354				148				—				26,502
Gain on derivative instruments			44,119				—				—				44,119
Total revenues			320,258				29,507				—				349,765
Costs and expenses
Lease operating			102,618				8,986				—				111,604
Transportation			1,772				2				—				1,774
Depreciation, depletion and amortization			150,387				11,905				—				162,292
Accretion of asset retirement obligations			10,252				2,027				—				12,279
Impairment of oil and natural gas properties			690,312				—				—				690,312
Goodwill impairment			329,293				—				—				329,293
General and administrative			14,852				—				—				14,852
Taxes, other than on earnings			599				3,873				—				4,472
Other			21				—				—				21
Total costs and expenses			1,300,106				26,793				—				1,326,899
Operating income (loss)			(979,848	)			2,714				—				(977,134	)
Other income (expense):
Other income, net			4				—				—				4
Interest expense			(21,848	)			—				—				(21,848	)
Income from equity investments			1,711				—				(1,711	)			—
Total other expense, net			(20,133	)			—				(1,711	)			(21,844	)
Income (loss) before income taxes			(999,981	)			2,714				(1,711	)			(998,978	)
Income tax benefit			(239,013	)			1,003				—				(238,010	)
Net income (loss)		$	(760,968	)		$	1,711			$	(1,711	)		$	(760,968	)

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EPL OIL & GAS, INC.
 
Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2015
(UNAUDITED)

		Parent Company Only				Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Net cash provided by operating activities		$	27,463			$	—			$	—			$	27,463
Cash flows used in investing activities:
Capital expenditures			(16,122	)			—				—				(16,122	)
Net cash used in investing activities			(16,122	)			—				—				(16,122	)
Cash flows provided by (used in) financing activities:
Payments on long-term debt			(3,395	)			—				—				(3,395	)
Cash restricted under revolving credit facility related to property sold			(30,008	)			—				—				(30,008	)
Advances from EGC			22,034				—				—				22,034
Debt issuance costs			(189	)			—				—				(189	)
Net cash used in financing activities			(11,558	)			—				—				(11,558	)
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		$	—			$	—			$	—			$	—

TABLE OF CONTENTS

EPL OIL & GAS, INC.
 
Supplemental Condensed Consolidating Statement of Cash Flows
Six Months Ended December 31, 2014
(UNAUDITED)

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

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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 “Item 1A. Risk Factors” included in our 2015 Annual Report and elsewhere in this Quarterly 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. For the six months ended December 31, 2015, our capital expenditures totaled approximately $67 million. Our current capital expenditures are allocated to development activities, which are geared toward the improvement of existing production and the performance of necessary plugging, abandonment and other decommissioning activities.

Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and financial liquidity carefully. We do not expect production increases from our fiscal year 2016 capital program to entirely offset production declines, resulting in slight decreases to our production. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate. In addition, in light of current commodity prices and our leverage position, in February 2016, Energy XXI engaged PJT Partners as a financial advisor and Vinson & Elkins L.L.P. as a legal advisor to advise its management and the Board, EGC and EPL regarding potential strategic alternatives such as a refinancing or restructuring of our indebtedness or capital structure or seeking to raise additional capital through debt or equity financing to address our liquidity issues and high debt levels. On February 16, 2016, we elected to enter into the 30-day grace period under the terms of the indenture governing the 8.25% Senior Notes to extend the timeline for making the cash interest payment to March 17, 2016. The aggregate amount of the interest payments is approximately $8.8 million. During the 30-day grace period, the Company, EGC and Energy XXI will work with their debt holders regarding their ongoing effort to develop and implement a comprehensive plan to restructure their balance sheets. For additional detail, see “— Liquidity — Overview.” We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. If we are unable to improve our liquidity position, refinance or restructure our debt obligations or are unsuccessful in implementing such strategic alternatives, we may seek bankruptcy protection to continue our efforts to restructure our business and capital structure and may have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements.

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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 and Impact on our Results of Operations, Compliance with Debt Instruments and Liquidity.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil and natural gas prices declined significantly during fiscal year 2015 and the decline has continued into fiscal year 2016. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from October 1, 2014 to December 31, 2015 ranged from a high of $91.01 to a low of $34.73, a decrease of 61.8%, and the NYMEX natural gas price per MMBtu for the period October 1, 2014 to December 31, 2015 ranged from a high of $4.49 to a low of $1.76, a decrease of 60.8%. As of December 31, 2015, the spot market price for WTI was $37.04. Oil prices have continued to decline in 2016, with the price of WTI crude oil per barrel dropping below $27.00 in January 2016 for the first time in twelve years. 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.

As of December 31, 2015, we were in compliance with our financial covenants under the Revolving Credit Facility; however, based on current market conditions and depressed commodity prices, if we are unable to execute on one of the strategic alternatives discussed below and adequately address liquidity concerns, we will not be in compliance with the consolidated net secured leverage ratio covenant under the Revolving Credit Facility for the quarter ending March 31, 2016. There is no assurance that we will be able to resolve such non-compliance with our lenders, which may result in a default under our Revolving Credit Facility. In addition, as described in greater detail under “— Liquidity and Capital Resources — Overview,” our ability to access available borrowing capacity under our Revolving Credit EPL Sub-Facility will be limited as a result of other provisions of the Revolving Credit Facility or a reduction in our borrowing base at our next redetermination in the spring of 2016. If we experience sustained periods of low prices for oil and natural gas, it will 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.

Reserve Quantities.  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. At December 31, 2015, our total proved reserves were 35.3 MMBOE. 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 January 29, 2016, we estimate that our total proved reserve equivalent volumes as of December 31, 2015 would have been approximately 2.2% higher 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. The Company’s proved reserves declined significantly compared to prior years and may decline in future years. Due to the depressed commodity prices and our lack of capital resources to develop our properties, the Company believes that all of its proved undeveloped oil and gas reserves no longer qualify as being proved as of the period ended December 31, 2015. We have thus removed all of our proved undeveloped oil and gas reserves from the proved category as of December 31, 2015. Almost all of the proved undeveloped reserves that were removed from the proved category as of December 31, 2015 are still economic at current prices, but were reclassed to the probable category because they are no longer expected to be drilled within five years of initial booking due to current constraints on ability to fund development drilling. In addition, as of December 31, 2015, we identified certain of our unevaluated properties totaling to $314.4 million as being uneconomical and have transferred such amounts to the full cost pool, subject to amortization.

Ceiling Test Write-down.  During the six months ended December 31, 2015, we recognized write-downs of our oil and natural gas properties totaling $812.9 million. The write-downs did not impact our cash flows from operating activities but did increase our net loss for the period and our stockholders’ deficit. Further

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ceiling test write-downs will 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 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 months ending January 31, 2016, we presently expect to incur further impairment of $75 million to $175 million in the third fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues, we will 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.

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.

BOEM Supplemental Financial Assurance and/or Bonding Requirements.  As of December 31, 2015, we had $189.7 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal OCS, approximately $67.2 million of our performance bonds are lease and/or area bonds issued to the BOEM that the BOEM has access to and 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 rather than to the BOEM, 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 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 and December 2015, we reached agreements with the BOEM with respect to which we provided $54.7 million and $8.9 million, respectively, of supplemental bonds issued to the BOEM (which is reflected in the $67.2 million in lease and/or area bonds discussed above). 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.

In October 2015, we received information from the BOEM indicating that we could 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-lessees losing their exemptions. However, we believe a substantial portion of the additional supplemental financial assurance and/or bonding that could 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. 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 but we can provide no assurance that such cooperation by these co-lessees will occur.

Since we received the additional information from the BOEM in October 2015, we have had a series of discussions and exchanges of information with the BOEM on the long-term financial assurance plan, culminating most recently in our submittal of an updated version of the long-term financial assurance plan to the BOEM for approval on February 2, 2016. The long-term plan calls for a series of actions by us during various dates in 2016, including by June 1, 2016 and September 1, 2016, which actions are designed to address the supplemental financial assurance liabilities initially identified by the BOEM, as such liabilities are further modified by the BOEM based on information we provide and our performance under the plan. This long-term plan requires approval by the BOEM in order for us to proceed with addressing these supplemental financial assurance liabilities. While we believe that the long-term financial assurance plan is close to being approved by the BOEM, we can provide no assurance as to a certain date by which the long-term plan will be approved or that the BOEM will not have further revisions to our proposal.

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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. 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 later if those items are not addressed in our plan.

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 Revolving Credit EPL Sub-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 Revolving Credit EPL Sub-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, cancelled or otherwise impose monetary penalties, and one or more of such actions could have a material adverse 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 “OSRP”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are approved by the Bureau of Safety and Environmental Enforcement (“BSEE”). The OSRP is reviewed at least annually, and updated as necessary, which updates also require BSEE approval. The OSRP specifications are consistent with the requirements set forth by the BSEE. Additionally, the OSRP is tested and drills are conducted annually at all levels of the Company.

We have contracted with a 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

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and pipeline companies operating in the Gulf of Mexico that has the appropriate equipment, including aircraft dispersant capabilities through its contract with Airborne Support Inc. and access to appropriate personnel to simultaneously respond to multiple spills. In the event of a spill, CGA mobilizes appropriate equipment and personnel to CGA members.

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

Results of Operations

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

Our consolidated net loss for the three months ended December 31, 2015 was $544.5 million as compared to $454.6 million for the three months ended December 31, 2014. The increase in the net loss was primarily due to no income tax benefit and lower revenues due to lower oil and natural gas sales prices in the second quarter of fiscal 2015, partially offset by lower impairment of oil and natural gas properties.

Revenues

		Three Months Ended December 31,								Decrease				Percent Decrease
		2015				2014
						(In thousands)
Oil		$	54,408			$	120,828			$	(66,420	)			(55.0	)%
Natural gas			8,256				12,548				(4,292	)			(34.2	)%
Gain on derivative financial instruments			906				22,262				(21,356	)			(95.9	)%
Total Revenues		$	63,570			$	155,638			$	(92,068	)			(59.2	)%

Our consolidated revenues decreased $92.1 million in the second 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 December 31,								Increase (Decrease)				Percent Increase (Decrease)				Revenue Increase (Decrease)
		2015				2014
																		(In thousands)
Price Variance
Oil sales prices (per Bbl)		$	38.18			$	71.12			$	(32.94	)			(46.3	)%		$	(55,958	)
Natural gas sales prices (per Mcf)			1.85				3.52				(1.67	)			(47.4	)%			(5,943	)
Gain on derivative financial instruments (per BOE)			0.42				9.71				(9.29	)			(95.7	)%			(21,356	)
Total price variance																			(83,257	)
Volume Variance
Oil sales volumes (MBbls)			1,425				1,699				(274	)			(16.1	)%			(10,462	)
Natural gas sales volumes (MMcf)			4,455				3,564				891				25.0	%			1,651
BOE sales volumes (MBOE)			2,167				2,293				(126	)			(5.5	)%
Percent of BOE from oil			66	%			74	%
Total volume variance																			(8,811	)
Total price and volume variance																		$	(92,068	)

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Price Variances

Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $83.3 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year. Average oil prices decreased $32.94 per barrel in the second quarter of fiscal 2016, resulting in lower revenues of $56.0 million. Average natural gas prices decreased $1.67 per Mcf in the second quarter of fiscal 2016 compared to the second quarter of fiscal 2015, resulting in lower revenues of $5.9 million. For the second quarter of fiscal 2016, our hedging activities resulted in a gain on derivative activities of $0.42 per BOE compared to a gain of $9.71 per BOE for the same period in the prior fiscal year, resulting in lower revenues of $21.4 million. The gain on derivatives for the three months ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $16.28 per barrel of oil.

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 will result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. As a result of our high level of indebtedness and commodity prices, we have significantly reduced our planned capital spending, and such curtailment of the development of our properties will eventually lead to a decline in our production and reserves. A decline in our production and reserves will further reduce our liquidity and ability to satisfy our debt obligations by negatively impacting our cash flow from operating activities and the value of our assets.

Volume Variances

Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes decreased 3.0 MBbls per day in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in lower revenues of $10.5 million. Natural gas sales volumes increased by 9.7 MMcf per day for the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, resulting in higher revenues of $1.7 million. Overall sales volumes decreased because of natural well declines, reduced drilling activity resulting in less new production, and irregular downtime due to third party pipelines. In the low commodity price environment, we expect to see further production declines due to natural declines and limited activity in the fields.

Costs and Expenses and Other (Income) Expense

		Three Months Ended December 31,																Increase (Decrease) Total $
		2015								2014
		Total $				Per BOE				Total $				Per BOE
		(In thousands, except per unit amounts)
Cost and expenses
Lease operating expense		$	30,889			$	14.25			$	55,304			$	24.12			$	(24,415	)
Transportation			664				0.31				1,149				0.50				(485	)
Depreciation, depletion and amortization			62,333				28.76				88,547				38.62				(26,214	)
Accretion of asset retirement obligations			6,317				2.92				6,098				2.66				219
Impairment of oil and natural gas properties			504,772				232.94				690,312				301.05				(185,540	)
General and administrative			9,978				4.60				6,810				2.97				3,168
Taxes, other than on earnings			39				0.02				1,944				0.85				(1,905	)
Total costs and expenses		$	614,992			$	283.80			$	850,164			$	370.77			$	(235,172	)
Other (income) expense
Other income, net		$	(2,393	)		$	(1.10	)		$	(4	)		$	—			$	(2,389	)
Gain on early extinguishment of debt			(21,269	)			(9.81	)			—				—				(21,269	)
Interest expense			16,772				7.74				10,947				4.77				5,825
Total other (income) expense, net		$	(6,890	)		$	(3.17	)		$	10,943			$	4.77			$	(17,833	)

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Costs and expenses decreased $235.2 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, principally due to the decrease in impairment of oil and gas properties, depreciation, depletion and amortization (“DD&A”) and lease operating expense 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 tests, we recognized ceiling test impairments of our oil and natural gas properties of $504.8 million for the quarter ended December 31, 2015 and $690.3 million for the quarter ended December 31, 2014.

Lease operating expense decreased $24.4 million in the second 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 and decrease in demand for oil field services. Lease operating expense per BOE declined from $24.12 for the quarter ended December 31, 2014 to $14.25 for the quarter ended December 31, 2015.

DD&A expense decreased $26.2 million in the second 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 $9.86. The decrease in the DD&A rate in the second 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 and 2016 resulting from the ceiling test, partially offset by the reduction in proved reserve estimates.

General and administrative expense increased $3.2 million in the second quarter of fiscal 2016 as compared to the same period in the prior fiscal year, primarily due to an increase in the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate.

Interest expense increased approximately $5.8 million in the second 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.

During the three months ended December 31, 2015, we repurchased $29.8 million of our 8.25% Senior Notes in open market transactions at a total cost of approximately $10.0 million, and we recorded a gain on the repurchases totalling approximately $21.3 million, including the amount of associated unamortized premium.

Income Taxes

The income tax expense for the second 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 second quarter of fiscal 2016 compared to income tax benefit of $250.9 million in the second quarter of fiscal 2015. For the second quarter of fiscal 2015, our effective income tax rate was 35.6%. 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. Please see Note 9 — Income Taxes in Notes to Consolidated Financial Statements in this Quarterly Report.

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Six Months Ended December 31, 2015 Compared to Six Months Ended December 31, 2014

Our consolidated net loss for the six months ended December 31, 2015 was $879.1 million as compared to $761.0 million for the six months ended December 31, 2014. The increase in the net loss was primarily due to lower revenues due to lower oil and natural gas sales prices, higher impairment of oil and natural gas properties, and no income tax benefit in the fiscal 2016 period.

Revenues

		Six Months Ended December 31,								Decrease				Percent Decrease
		2015				2014
						(In thousands)
Oil		$	127,780			$	279,144			$	(151,364	)			(54.2	)%
Natural gas			20,874				26,502				(5,628	)			(21.2	)%
Gain on derivative financial instruments			3,684				44,119				(40,435	)			(91.6	)%
Total Revenues		$	152,338			$	349,765			$	(197,427	)			(56.4	)%

Our consolidated revenues decreased $197.4 million in the first six months 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

		Six Months Ended December 31,								Increase (Decrease)				Percent Increase (Decrease)				Revenue Increase (Decrease)
		2015				2014
																		(In thousands)
Price Variance
Oil sales prices (per Bbl)		$	41.69			$	83.05			$	(41.36	)			(49.8	)%		$	(139,024	)
Natural gas sales prices (per Mcf)			2.26				3.72				(1.46	)			(39.1	)%			(10,372	)
Gain on derivative financial instruments (per BOE)			0.80				9.70				(8.90	)			(91.7	)%			(40,435	)
Total price variance																			(189,831	)
Volume Variance
Oil sales volumes (MBbls)			3,065				3,361				(296	)			(8.8	)%			(12,340	)
Natural gas sales volumes (MMcf)			9,223				7,127				2,096				29.4	%			4,744
BOE sales volumes (MBOE)			4,602				4,549				53				1.2	%
Percent of BOE from oil			67	%			74	%
Total volume variance																			(7,596	)
Total price and volume variance																		$	(197,427	)