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

 

Form 10-K

 

(Mark One)
x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended June 30, 2015
		or
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from            to

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

 

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes x No o

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 o No x

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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 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.

OMISSION OF CERTAIN INFORMATION:

EPL Oil & Gas, Inc. meets the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

DOCUMENTS INCORPORATED BY REFERENCE:

None

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		Page
PART I
Cautionary Statement Concerning Forward Looking Statements			1
Item 1. Business			3
Item 1A. Risk Factors			18
Item 1B. Unresolved Staff Comments			40
Item 2. Properties			40
Item 3. Legal Proceedings			40
Item 4. Mine Safety Disclosures			40
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			41
Item 6. Selected Financial Data			41
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			41
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			70
Item 8. Financial Statements and Supplementary Data			72
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure			73
Item 9A. Controls and Procedures			74
Item 9B. Other Information			75
PART III
Item 10. Directors, Executive Officers and Corporate Governance			76
Item 11. Executive Compensation			76
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			76
Item 13. Certain Relationships and Related Transactions, and Director Independence			76
Item 14. Principal Accountant Fees and Services			76
PART IV
Item 15. Exhibits and Financial Statement Schedules			77

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K (this “Form 10-K”) 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 read (1) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-K, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (3) other public announcements we make from time to time.

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.

EXPLANATORY NOTE — RESTATEMENT OF FINANCIAL INFORMATION

In connection with preparing this Form 10-K, we determined that the contemporaneous formal documentation that we had prepared subsequent to our merger with Energy XXI Ltd to support our designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment applied subsequent to our merger with Energy XXI Ltd, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues. As a result, we concluded that certain of our previously issued consolidated financial statements should no longer be relied upon and would need to be restated.

This Form 10-K for the year ended June 30, 2015 includes (1) a restated balance sheet as of June 30, 2014, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the period from June 4, 2014 through June 30, 2014, and (3) restated quarterly consolidated financial statements for the quarters ended September 30, 2014, December 31, 2014, and March 31, 2015. See Item 8, “Financial Statements and Supplementary Data,” and Item 9A, “Controls and Procedures,” in Part II of this Form 10-K, including Notes 17 and 18 of the notes to the Consolidated Financial Statements, for more information concerning these restatements. The consolidated financial statements for prior periods presented in this report have been restated primarily to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) as gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling tests, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement.

We do not plan to amend previously filed reports in connection with the restatement. The consolidated financial statements that have been previously filed or otherwise reported for these periods are superseded by the information in this Form 10-K. Other than the historical information reported for the Predecessor Company for periods prior to our merger with Energy XXI Ltd, all financial and accounting information contained in this Form 10-K is presented on a restated basis.

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PART I

Overview

EPL Oil & Gas, Inc. (referred to herein as “we,” “our,” “us,” “EPL” or the “Company”) was incorporated as a Delaware corporation in January 1998 and is a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”), a Delaware corporation and indirect wholly-owned subsidiary of Energy XXI Ltd, an exempted company under the laws of Bermuda and our ultimate parent company (“Energy XXI” or “parent”).

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 and related matters are addressed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our current operations are concentrated in the U.S. Gulf of Mexico shelf (the “GoM shelf”) focusing on state and federal waters offshore Louisiana, which we consider our core area. We have focused on acquiring and developing assets in this region, because the region is characterized by established exploitation, development and exploration opportunities in both productive horizons and deeper geologic formations. As part of Energy XXI’s overall strategy and capital plan, we are focused on developing high quality oil-producing assets with low production decline rates. As of June 30, 2015, we had estimated proved reserves of 57.2 Mmboe, of which 67% were oil and 76% were proved developed. Of these proved developed reserves, 70% were oil reserves.

We produce both oil and natural gas. Throughout this Form 10-K, 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 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 Form 10-K.

For definitions of oil and natural gas terms used frequently in this Form 10-K, please refer to the “Glossary of Oil and Natural Gas Terms” following the index of Exhibits in Item 15 of Part IV of this Form 10-K.

Available Information

We file or furnish annual, quarterly and current reports and other documents with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934 (as amended, the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

Energy XXI maintains a website at www.energyxxi.com that contains information about us, which information is available free of charge, including links to our Annual and Transition Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all related amendments as soon as reasonably practicable after electronically filing such reports with, or furnishing them to the SEC. The Energy XXI website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Form 10-K or any other filing that we make with the SEC.

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Properties

As of June 30, 2015, we had working interests in 27 producing fields located in the GoM shelf region. The proved reserves and production from these fields are primarily associated with the following core producing areas: Ship Shoal 208, South Pass 49, West Delta 30 and South Pass 78. These properties represent approximately 74% of our net proved reserves and are ranked based on highest proved reserves as of June 30, 2015.

Ship Shoal 208.  We operate and have a 100% working interest in the Ship Shoal 208 field, located 110 miles southwest of New Orleans, Louisiana in approximately 100 feet of water on Outer Continental Shelf (“OCS”) blocks Ship Shoal 208, 209 and 215. We have 13 platforms and 31 active wells throughout the field. The field’s net production for the month of June 2015 of 4.8 MBOED accounted for approximately 17% of our net production. Net proved reserves for the field were 70% oil at June 30, 2015.

South Pass 49.  Energy XXI operates and we have a 100% working interest in the South Pass 49 field, which is located near the mouth of the Mississippi River in approximately 400 feet of water. There are 14 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 121 MMBOE. The field’s net production for the month of June 2015 of 4.6 MBOED accounted for approximately 17% of our net production. Net proved reserves for the field were 62% oil at June 30, 2015.

West Delta 30.  We operate and have an average 93% working interest in the West Delta 27, 28 and 29 blocks, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on the OCS. There are 46 active wells located throughout the field. The field’s net production for the month of June 2015 of 5.2 MBOED accounted for approximately 19% of our net production. Net proved reserves for the field were 86% oil at June 30, 2015.

South Pass 78.  We operate and own a working interest of 67% in the South Pass 78 complex, which is located 86 miles southeast of New Orleans. It contains 31 producing wells in water depths ranging from approximately 140 to 190 feet in four lease blocks. There are four major production platforms, three of which have producing wells, located throughout the field. The field’s net production for the month of June 2015 of 2.7 MBOED accounted for approximately 10% of our net production. Net proved reserves for the field were 52% oil at June 30, 2015.

As of June 30, 2015, we also owned interests in one undeveloped lease in the deepwater Gulf of Mexico and we have a non-operated interest in one developed lease. Our working interests in our leases in this area ranged from 15% to 33%.

On June 30, 2015, we sold our interest in the East Bay field for cash consideration of approximately $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. This area included the South Pass 24 and 27 fields and is located 89 miles southeast of New Orleans, near the mouth of the Mississippi River. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for additional information regarding the terms of the sale of our interests in the East Bay field.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for information regarding our oil and gas production, average prices and average costs.

Summary of Oil and Natural Gas Reserves at June 30, 2015

The following table presents our estimated net proved oil and natural gas reserves and the estimated future net revenues and cash flows related to our reserves at June 30, 2015. Our estimates of proved reserves are based on a reserve report prepared as of June 30, 2015 by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. Neither PV-10 nor the standardized measure of discounted future net cash flows shown in the table is intended to represent the current market value of the estimated oil and natural gas reserves that we own. Note 19 “Supplementary Oil and Natural Gas

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Disclosures — (Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Form 10-K provides important additional information about our proved oil and natural gas reserves.

We follow the oil and gas reserves estimation and disclosure requirements of the Financial Accounting Standards Board Accounting Standards Codification (“ASC”) Topic 932, “Extractive Activities — Oil and Gas” (“ASC 932”), which requires, among other things, that prices used to estimate reserves for SEC disclosure purposes reflect an unweighted, arithmetic average price based upon the closing price on the first day of each of the twelve months during the fiscal year, rather than the year-end price. See Note 19 “Supplementary Oil and Natural Gas Disclosures — (Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Form 10-K for additional information regarding reporting related to oil and natural gas reserves under ASC 932.

		As of June 30, 2015
		(dollars in thousands)
Total net proved reserves:
Oil (Mbbls)			38,623
Natural gas (Mmcf)			111,586
Total (Mboe)			57,219
Net proved developed reserves(1):
Oil (Mbbls)			30,804
Natural gas (Mmcf)			77,562
Total (Mboe)			43,731
Net proved undeveloped reserves:
Oil (Mbbls)			7,819
Natural gas (Mmcf)			34,024
Total (Mboe)			13,490
Present value of estimated future net revenues before income taxes (PV-10)(2)(3)(5)		$	825,766
Standardized measure of discounted future net cash flows(4)(5)		$	825,766

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Changes in Proved Reserves

Our proved developed reserve estimates decreased by 18.4 MMBOE or 30% to 43.7 MMBOE at June 30, 2015 from 62.1 MMBOE at June 30, 2014. The decrease was primarily due to:

Offset by:

Our proved undeveloped reserve estimates decreased by 13.9 MMBOE or 51% to 13.5 MMBOE at June 30, 2015 from 27.4 MMBOE at June 30, 2014. The decrease was primarily due to:

Development of Proved Undeveloped Reserves

Our proved undeveloped (“PUD”) reserves at June 30, 2015 were 13.5 MMBOE. Future development costs associated with our PUD reserves at June 30, 2015 totaled approximately $203 million. In the fiscal year ended June 30, 2015, we developed approximately 9.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 8 gross, 8 net wells at a net cost of approximately $80 million.

As part of Energy XXI’s development plan, our reserves development plan is updated on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon Energy XXI’s long range criteria, including top value projects, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in Energy XXI’s long range plan, all of our PUD locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report.

Although the schedule for development of our PUDs has historically changed based on external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in a given area, and our current PUD schedule is also subject to change due to external factors, we believe our PUDs will be converted in a timely manner given our enhanced focus on development drilling in our long range plan and current availability of capital to execute that plan. Energy XXI senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan. The following table presents the percentage of PUD reserves scheduled to be developed by fiscal year, in accordance with our long range plan.

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Year Ending June 30,		Percentage of PUD Reserves Scheduled to be Developed
2017			4	%
2018			28	%
2019			65	%
2020			3	%
Total			100	%

The following table discloses our progress toward the development of PUD reserves during the fiscal year ended June 30, 2015.

		Oil and Natural Gas				Future Development Costs
		(MBOE)				(in thousands)
Proved undeveloped reserves at June 30, 2014			27,386			$	402,604
Extensions and discoveries			250				7,750
Revisions of previous estimates			(10,146	)			(59,830	)
Changes in prices and costs			(1,018	)			(55,332	)
Sales of reserves			(402	)			(12,400	)
Conversions to proved developed reserves			(2,580	)			(80,062	)
Total reduction in proved undeveloped reserves			(13,896	)			(199,874	)
Proved undeveloped reserves at June 30, 2015			13,490			$	202,730

Qualifications of Primary Internal Engineer and Third Party Engineers

Energy XXI’s Director of Reserves, Lee I. Williams, is the technical person primarily responsible for overseeing the preparation by NSAI of our reserve estimates and for compliance with Energy XXI’s policies. He has 15 years of industry experience with positions of increasing responsibility and has over 10 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1998 with a Bachelor of Science Degree in Petroleum Engineering.

At the end of each year, our reserve estimates are prepared by outside petroleum engineering firms. As of June 30, 2015, our estimates of proved reserves are based on a reserve report prepared by the independent petroleum engineering firm NSAI, a nationally recognized engineering firm. At June 30, 2015, 100% of our total estimated net proved reserves were prepared by NSAI. The NSAI report is filed as an exhibit to this Form 10-K.

NSAI provides a complete range of geological, geophysical, petrophysical and engineering services and has the technical experience and ability to perform these services in any of the onshore and offshore oil and gas producing areas of the world. NSAI has a technical staff of over 70 professionals who are knowledgeable with regard to recognized industry reserves and resource definitions, specifically those set forth by the SEC. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Connor B. Riseden and Mr. Shane M. Howell.

Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Licensed Professional Engineer in the State of Texas (No. 100566) and has over 13 years of practical experience in petroleum engineering. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. Mr. Howell has been practicing consulting petroleum geoscience at NSAI since 2005. Mr. Howell is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11276) and has over 17 years of practical experience in petroleum geosciences. He graduated from San Diego State University in 1997 with a Bachelor of Science Degree in Geological Sciences and in 1998 with a Master of Science Degree in Geological Sciences.

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Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Technologies Used in Reserve Estimation

The SEC allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” is defined by the SEC as “much more likely to be produced than not” and “much more likely to increase or remain constant than to decrease.” Our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, pressure data and reservoir simulation.

Oil and Natural Gas Production, Prices and Production Costs — Significant Fields

The table below sets forth production information for each field that contains 15% or more of our total proved reserves as of June 30, 2015. On June 3, 2014, we acquired from Energy XXI GOM, LLC additional oil and natural gas interests in our South Pass 49 field. The table below reflects production for this field based on our historical interests in this field prior to the recent acquisition of the additional interests and includes production associated with the additional interests subsequent to June 3, 2014.

		Year Ended June 30, 2015				Six Months Ended June 30, 2014				Year Ended December 31,
										2013				2012
Ship Shoal 208:
Oil (Mbbls)			1,259				540				658				109
Natural gas (Mmcf)			2,397				547				1,130				199
Total (Mboe)			1,659				631				846				142
South Pass 49:
Oil (Mbbls)			726				138				163				86
Natural gas (Mmcf)			4,383				1,110				2,512				401
Total (Mboe)			1,457				323				582				153
West Delta 30:
Oil (Mbbls)			1,511				885				2,293				1,142
Natural gas (Mmcf)			2,722				397				2,000				490
Total (Mboe)			1,965				951				2,626				1,224

Costs Incurred in Oil and Natural Gas Activities

The following table sets forth the costs incurred associated with finding, acquiring and developing our proved oil and natural gas reserves.

		Year Ended June 30, 2015				Six Months Ended June 30, 2014				Year Ended December 31,
										2013				2012
		(In thousands)
Acquisitions – Proved		$	—			$	314,169			$	46,047			$	706,322
Acquisitions – Unevaluated			176				9,503				2,200				7,496
Exploration			27,100				56,079				46,100				43,338
Development			244,216				242,217				303,245				180,938
Costs incurred		$	271,492			$	621,968			$	397,592			$	938,094

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Oil and Natural Gas Production and Prices

Our average daily production represents our net ownership and includes royalty interests and net profit interests owned by us. Our average daily production and average sales prices follow.

		Year Ended June 30, 2015				Six Months Ended June 30, 2014				Year Ended December 31,
										2013				2012
Sales Volumes per Day
Oil (MBbls)			18.3				17.3				16.9				10.4
Natural gas (Mmcf)			43.7				26.5				32.9				17.9
Total (MBOE)			25.6				21.7				22.4				13.4
Percent of BOE from oil			72	%			80	%			76	%			78	%
Average Sales Price
Oil per Bbl		$	67.66			$	99.87			$	104.01			$	106.08
Natural gas per Mcf		$	3.14			$	4.92			$	3.81			$	2.89
Sales price per BOE		$	58.04			$	82.74			$	84.18			$	86.33

Production Unit Costs

Our production unit costs follow. Production costs include lease operating expense and production taxes.

		Year Ended June 30, 2015				Six Months Ended June 30, 2014				Year Ended December 31,
										2013				2012
Average Cost per BOE
Production costs
Lease operating expense		$	22.68			$	22.93			$	20.27			$	19.38
Production taxes			0.87				1.33				1.40				2.66
Total production costs		$	23.55			$	24.26			$	21.67			$	22.04
Depreciation, depletion and amortization rates		$	31.99			$	27.47			$	24.49			$	23.21

Productive Wells

The following table sets forth the number of productive oil and natural gas wells in which we owned an interest as of June 30, 2015 and 2014.

		June 30,
		2015								2014
		Gross				Net				Gross				Net
Oil			213				167				359				314
Natural gas			45				33				79				58
Total			258				200				438				372

In this Form 10-K, when referring to wells and acreage, “gross” refers to the total wells or acres in which we have a working interest and “net” refers to gross wells or acres multiplied by our working interest.

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Acreage

The following table sets forth information relating to acreage held by us as of June 30, 2015. Developed acreage is assigned to producing wells.

		June 30, 2015
		Developed Acres								Undeveloped Acres								Total Acres
		Gross				Net				Gross				Net				Gross				Net
Onshore			—				—				125				63				125				63
Offshore			236,197				188,626				181,164				153,306				417,361				341,932
Total			236,197				188,626				181,289				153,369				417,486				341,995

During fiscal years 2016 and 2017, we do not have any leases covering our undeveloped acreage expiring; however, during fiscal year 2018, leases covering 42,903 of our undeveloped gross acreage (32,697 net) will expire.

Drilling Activity

Drilling activity refers to the number of wells completed at any time during the applicable fiscal years, regardless of when drilling was initiated. The following table shows our drilling activity where “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest in these wells.

		Year Ended June 30, 2015								Six Months Ended June 30, 2014								Year Ended December 31,
																		2013								2012
		Gross				Net				Gross				Net				Gross				Net				Gross				Net
Development Wells
Productive			7.0				7.0				10.0				9.5				13.0				11.5				11.0				9.5
Non-productive			—				—				—				—				3.0				3.0				1.0				1.0
Total			7.0				7.0				10.0				9.5				16.0				14.5				12.0				10.5
Exploratory Wells
Productive			2.0				1.5				1.0				0.5				—				—				1.0				0.8
Non-productive			1.0				0.6				1.0				1.0				1.0				1.0				2.0				0.7
Total			3.0				2.1				2.0				1.5				1.0				1.0				3.0				1.5

Present Activities

As of June 30, 2015, we were not in the process of drilling any wells.

Delivery Commitments

We had no delivery commitments in the three years ended June 30, 2015.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, mechanics’ and materialman’s liens, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with the use of our properties or the operation of our business.

We believe that we have satisfactory title to, or rights in, all of our properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. We investigate title prior to the consummation of an acquisition of producing properties and before the commencement of drilling operations on undeveloped properties. We have obtained or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and natural gas industry.

Government Regulation

Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such

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rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

Regulations affecting production.  The jurisdictions in which we operate generally require permits for drilling operations, drilling bonds and operating reports and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.

These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. There is generally no regulation of wellhead prices or other, similar direct economic regulation of production, but there can be no assurance that this will remain true in the future.

In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.

Regulations affecting sales.  The sales prices of oil, natural gas liquids and natural gas are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.

The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Rates charged and terms of service for the interstate pipeline transportation of oil, natural gas liquids and other refined petroleum products also are regulated by FERC. FERC has established an indexing methodology for changing the interstate transportation rates for oil pipelines, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Market manipulation and market transparency regulations.  Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. Likewise, the Federal Trade Commission (“FTC”) holds authority to regulate wholesale petroleum

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markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, natural gas liquids, and crude oil, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC, FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation or, for the CFTC, triple the monetary gain to the violator, order disgorgement of profits, and recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has issued certain market transparency rules pursuant to its EPAct 2005 authority, which may affect some or all of our operations. FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. FERC’s civil penalty authority under EPAct 2005 applies to violations of Order 704.

Oil Pipeline Regulations.  We own interests in oil pipelines regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and the rules and regulations promulgated under those laws and, thus, have interstate tariffs on file with FERC setting forth our interstate transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil, natural gas liquids and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.

Under the EPAct of 1992, oil pipeline rates in effect for the 365-day period ending on the date of enactment of the EPAct of 1992 are deemed to be just and reasonable under the ICA, if such rates were not subject to complaint, protest or investigation during that 365-day period. These rates are commonly referred to as “grandfathered rates.” FERC may change grandfathered rates upon complaint only after it is shown that (i) a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate; (ii) the complainant was contractually barred from challenging the rate prior to enactment of the EPAct of 1992 and filed the complaint within 30 days of the expiration of the contractual bar; or (iii) a provision of the tariff is unduly discriminatory or preferential. The EPAct of 1992 places no similar limits on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.

The EPAct of 1992 further required FERC to establish a simplified and generally applicable ratemaking methodology for interstate oil pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows oil pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, plus 2.65 percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding is limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. The indexing methodology is applicable to any existing rate, including a grandfathered rate. Indexing includes the requirement that, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. However, the pipeline is not required to reduce its rates below the level deemed just and reasonable under the EPAct of 1992.

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While an oil pipeline, as a general rule, must use the indexing methodology to change its rates, FERC also retained cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement.

Outer Continental Shelf Regulations.  Our operations on federal oil and gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency, (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of another Gulf of Mexico operator, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $566.5 million of requested supplemental bonding was reduced by approximately $178 million.

On September 22, 2015, the BOEM issued draft guidance (the “Draft Guidance”) describing revised supplemental bonding procedures the agency plans to use to impose financial assurance obligations for decommissioning activities on the federal OCS. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised Notice to Lessees (“NTL”) in replacement of an existing NTL on supplemental bonding that was made effective on August 28, 2008. Among other things, the Draft Guidance proposes to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS projecting a relatively large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations by self-insuring for those liabilities, but only so long as the cumulative decommissioning liability amount being self-insured by the operator is no more than 50% of the operator’s net worth. Under the Draft Guidance, this waiver option would be eliminated in favor of a broadened self-insurance approach that would allow a larger array of operators on the OCS, not just those with relatively large net worths, who meet certain criteria to seek self-insurance for a portion of their supplemental bond obligations, but eligible operators may only self-insure for an amount that is no more than 10% of their tangible net worth. Under the Draft

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Guidance, the BOEM proposes to establish 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 requires payment of the supplemental bonding amount in three approximately equal installments of one-third each, by no later than approximately 120, 240 and 360 calendar days, respectively, from the date of BOEM approval of the tailored plan. We currently expect the Draft Guidance to be finalized and a new NTL to be issued by late 2015 or early 2016.

We currently maintain approximately $58.3 million in lease and/or area bonds issued to the BOEM and approximately $122.5 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $180.8 million, with an annual premium expense of $2.7 million. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements. Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, in addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the BOEM, the BOEM is actively seeking to adjust its financial assurance requirements mandated by rule for all companies operating in federal waters. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking (“ANPR”) in which the agency indicated that it was considering bolstering the financial assurance requirements currently mandated by rule. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. Please read “Risk Factors — We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”

Under certain circumstances, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. We own certain crude oil pipelines located on the OCS. BSEE regulates terms of service on OCS pipelines to provide open and nondiscriminatory access.

Gathering regulations.  Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. The classification and regulation of our gathering lines may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural

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gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.

Environmental Regulations

Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, the establishment of financial assurance requirements for oil spill response costs and the decommissioning of offshore facilities and the remediation of contaminated sites. These laws and regulations may impose liabilities for noncompliance and contamination resulting from our operations and may require suspension or cessation of operations in affected areas.

The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations, as amended from time to time:

We believe our operations are in compliance with applicable environmental laws and regulations. We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements on “responsible parties” related to the prevention of and response to oil spills into waters of the United States, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns joint and several, strict liability, without regard to fault, to each

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responsible party, for all containment and cleanup costs and a variety of public and private damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

Climate Change.  The U.S. Environmental Protection Agency (the “EPA”) has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore and offshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40 to 45% from 2012 emission levels by 2025. Subsequent to this announcement, on September 18, 2015, the EPA published a proposed rulemaking that includes new limits for methane emissions and expanded limits for volatile organic compound emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. As the number of emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Derivative Activities

We are actively engaged in a hedging program designed to manage our commodity price risk and enhance cash flow certainty and predictability. For further information regarding our risk management activities, please read Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in this Form 10-K.

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Marketing and Significant Customers

We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated oil and gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

Of our total oil and natural gas revenues for the year ended June 30, 2015, Chevron USA, Inc. (“Chevron”) accounted for approximately 58%, ConocoPhillips accounted for approximately 20%, and Shell Trading (US) Company (“Shell”) accounted for approximately 20%. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Chevron, ConocoPhillips or Shell curtailed their purchases.

We transport a portion of our oil and natural gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. Our ability to market our oil and gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties has been and could continue to be adversely impacted.

Employees

Effective January 1, 2015, all remaining EPL employees became employees of Energy XXI Services, LLC, an affiliated party.

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

Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil prices declined severely during our 2015 fiscal year with continued lower prices in the first quarter of our fiscal year 2016. The WTI crude oil price per barrel for the period from July 1, 2014 to June 30, 2015 ranged from a high of $105.34 to a low of $43.46, a decrease of 58.7%, and the NYMEX natural gas price per MMBtu for the period July 1, 2014 to June 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 22, 2015, the spot market price for WTI was $45.83. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. The speed and severity of the decline in oil prices during our 2015 fiscal year and the continued lower prices in the first quarter of our fiscal year 2016 has materially affected our results of operations and our estimates of our proved oil and natural gas reserves. Any sustained periods of low prices for oil or natural gas are likely to materially and adversely affect our financial position, the quantities of natural gas and oil reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds from EGC and EGC’s ability to access funds under our revolving credit facility and through the capital markets.

We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.

As of June 30, 2015, we had total indebtedness of $1,018 million. Based on our current debt balance, we expect to have substantial interest payments due during fiscal year 2016, totaling $80.1 million. In addition, our $510 million aggregate principal amount 8.25% Senior Notes are due February 15, 2018.

In addition, our revolving credit facility is scheduled to mature on April 9, 2018; however, the maturity of our revolving credit facility will accelerate if EGC’s 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or our 8.25% Senior Notes are not retired or refinanced by July 15, 2017.

Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and

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certain financial, business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or repay our indebtedness as it becomes due or to fund our other liquidity needs. In addition, there can be no assurance that we will have the ability to borrow or otherwise raise the amounts necessary to repay or refinance our indebtedness as it matures. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we may be required to:

EGC and EPL may be unable to restructure or refinance our debt, obtain additional financing or capital or sell assets on satisfactory terms, if at all. If we cannot make scheduled payments on our debt, we will be in default under the terms of the agreements governing our debt and, as a result:

Our significant level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities. In addition, the covenants in the indentures governing our senior notes and our revolving credit facility impose restrictions that may limit our ability to take certain actions. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

As of June 30, 2015, we had total indebtedness of $1,018 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:

In addition, our revolving credit facility contains and our indentures governing our unsecured notes contain covenants that restrict our ability to take various actions, such as:

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In addition, under our revolving credit facility, there is a restriction on changes in our management. If John D. Schiller, Jr. ceases to be the chief executive officer of our parent company Energy XXI Ltd (except as a result of his death or disability) and a reasonably acceptable successor is not appointed within 180 days, the lenders of our revolving credit facility could declare amounts outstanding thereunder immediately due and payable. In the event that Mr. Schiller ceases to be our parent’s chief executive officer, amounts outstanding under our revolving credit facility would not automatically be reclassified as current debt as it is probable that we could identify a successor within the 180 day period. Our revolving credit facility requires, and any future credit facilities may require, us to comply with specified financial ratios, including regarding interest coverage and total leverage coverage.

Our ability to comply with these covenants will likely be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A prolonged period of oil and gas prices at current levels or a further decline could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. A breach of any of these provisions could result in a default under our debt instruments, which could allow all amounts outstanding thereunder to be declared immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes in the event of acceleration of our outstanding indebtedness. In the event of such acceleration, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us. We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under these instruments.

We may be able to incur additional debt in the future. This could exacerbate the risks associated with our indebtedness.

Despite our current level of indebtedness, we may incur more debt in the future, which could further exacerbate the risks described above. The terms of the indentures governing our senior notes and our revolving credit facility do not fully prohibit us or our subsidiaries from incurring more indebtedness, which could intensify the related risks that we now face.

Continued low commodity prices may impact our ability to comply with debt covenants

Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement for the near term; however, a protracted period of low commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods, including prior to June 30, 2016. A breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. If the lenders under our credit facility were to accelerate the indebtedness under our revolving credit facility as a result of such defaults, such acceleration of outstanding indebtedness under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness, as well as all of EGC’s and our parent’s other outstanding indebtedness. As of June 30, 2015, EGC and our parent had outstanding indebtedness of $3,916 million, excluding all of our

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

We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.

We expect to make substantial capital expenditures related to our oil and gas properties. Our capital requirements depend on numerous factors making it difficult to predict the timing and amount of our capital expenditures. We intend to primarily finance our capital expenditures with advances from EGC which intends to primarily finance near term capital expenditures with cash on hand. However, if our capital requirements vary materially from those provided for in EGC’s current projections, we or EGC may require additional financing. A decrease in expected revenues or an adverse change in market conditions could make obtaining this financing economically unattractive or impossible.

The cost of raising money in the debt and equity capital markets may increase substantially while the availability of funds from those markets may diminish significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets may increase as lenders and institutional investors could increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, cease to provide funding to borrowers.

An increase in our indebtedness, as well as the credit market and debt and equity capital market conditions discussed above could further negatively impact our ability to remain in compliance with the financial covenants under our revolving credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may be less favorable to us, or not pursue growth opportunities.

Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.

We have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of another Gulf of Mexico operator, the BOEM indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $54.7 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and

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postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $566.5 million of requested supplemental bonding was reduced by approximately $178 million.

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. Further, 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 requires payment of the supplemental bonding amount in three equal installment 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.

We currently maintain approximately $58.3 million in lease and/or area bonds issued to the BOEM and approximately $122.5 million in bonds issued to predecessor third party assignors of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $180.8 million, with an annual premium expense of $2.7 million. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for certain other properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements.

Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, in addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the BOEM, the BOEM is actively seeking to adjust its financial assurance requirements mandated by rule for all companies operating in federal waters. In August 2014, the BOEM issued an ANPR in which the agency indicated that it was considering bolstering the financial assurance requirements currently mandated by rule. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations include the U.S. Gulf of Mexico.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases

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to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance of a NTL, effective October 2010, that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The idle iron NTL establishes new triggers for commencing decommissioning activities —  any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time. Plugging or abandonment of wells may be delayed by two years if all of such wells’ hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. Moreover, as a result of the implementation of this NTL, there is expected to be increased demand for salvage contractors and equipment operating in the U.S. Gulf of Mexico, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.

In addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the BOEM, in August 2014, the BOEM issued an ANPR in which the agency indicated that it was considering increasing the financial assurance requirements mandated by rule. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Please read “Risk Factors — We have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”

Lower oil and gas prices and other factors may result in ceiling test write-downs of our asset carrying values.

Under the full cost method of accounting, we are required to perform each quarter, a “ceiling test” that determines a limit on the book value of our oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unevaluated oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10%, net of related tax effects, plus the cost of unevaluated oil and gas properties, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule based on the average prices for oil and natural gas. However, if prior to the balance sheet date, we enter into certain hedging arrangements for a portion of our future natural gas and oil production, thereby enabling us to receive future cash flows that are higher than the estimated future cash flows indicated, these higher hedged prices are used if they qualify as cash flow hedges.

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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. For the second, third and fourth quarters of fiscal year 2015, we recognized ceiling test write-downs of our oil and natural gas properties totaling $1,678.8 million.

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 for the 12 months ending September 30, 2015, we presently expect to incur an impairment of $300 million to $500 million in the first fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues beyond first fiscal quarter of 2016, we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.

This Form 10-K contains estimates of our future net cash flows from our proved reserves. We base the estimated discounted future net cash flows from our proved reserves on average prices for the preceding twelve-month period and costs in effect at the time of the estimate. As a result of significant recent declines in commodity prices, such average sales prices are significantly in excess of more recent prices. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease as additional months with lower commodity sales prices will be included in this calculation in the future. Actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our actual recovery of reserves may differ from our proved reserve estimates.

This Form 10-K contains estimates of our proved oil and gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also

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materially affect the estimated quantities of reserves shown in the reserve reports summarized in this Form 10-K. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.

We have included in this Form 10-K certain estimates of our proved reserves as of June 30, 2015 prepared in a manner consistent with our interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent petroleum consultant who prepares our reserve estimates. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may have to write off reserves previously recognized as proved undeveloped. We cannot assure you that our long-term plans will not change based on commodity prices, costs or our liquidity in a manner that would require us to reduce our proved reserve estimate in the future due to the five-year development rule or otherwise. During the year ended June 30, 2015, we were required to reduce proved reserve estimates by 2.8 Mmboe due to the five year development rule.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

Approximately 24% of our proved reserves as of June 30, 2015 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserves data included in the reserves engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. In addition, there are external factors such as such as changes in commodity prices, the availability of capital, the availability of drilling rigs (capable of drilling in the given area), that could result in certain development plans being delayed and/or accelerated relative to the current schedule.

Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. For example, our proved reserves of 57.2 Mmboe and $826 million of PV-10 as of June 30, 2015 were lower than our proved reserves of 89.5 Mboe and $2,482 million of PV-10 as of June 30, 2014 in part due to the rescheduling or write off of certain of our reserves as a result of lower oil and gas prices and reductions in our capital expenditure budget as compared to our June 30, 2014 reserve report. Delays in the development of these reserves could cause us to have to reclassify our proved reserves as unproved reserves. Please read “Business — Development of Proved Undeveloped Reserves.”

As of June 30, 2015, approximately 24% of our total proved reserves were undeveloped and approximately 23% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.

While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that all of those reserves will ultimately be developed or produced. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.

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Unless we replace crude oil and natural gas reserves, our future reserves and production will decline.

A large portion of our drilling activity is located in mature oil-producing areas of the GoM shelf. Accordingly, increases in our future crude oil and natural gas production depend on our success in finding or acquiring additional reserves that are economically recoverable. If we are unable to replace reserves through drilling or acquisitions on economic terms, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in obtaining funds to acquire additional reserves.

Production periods or reserve lives for Gulf of Mexico properties subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the U.S. Typically, 50% of the reserves of properties in the Gulf of Mexico are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.

The borrowing base under our revolving credit facility may be reduced in the future if commodity prices decline, which will limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.

We and EGC depend on the revolving credit facility for a portion of its future capital needs. As of June 30, 2015, our borrowing base under our revolving credit sub-facility was $150 million of the total $500 million borrowing base of EGC’s revolving credit facility. As of June 30, 2015, we had borrowed the full $150 million.

In the future, we and EGC may not be able to access adequate funding under the revolving credit facility as a result of (1) a decrease in the borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of the lending counterparties to meet their funding obligations.

Our borrowing base will be redetermined semi-annually by our lenders in their sole discretion. We expect the next determination of the borrowing base under the revolving credit facility will occur in the fall of 2015, although an early redetermination is possible. In addition, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. If oil and natural gas commodity prices continue to deteriorate, the revised borrowing base under our revolving credit facility may be reduced. If the borrowing base is reduced or maintained, the new borrowing base is subject to approval by banks holding not less than 67% of the lending commitments under our revolving credit facility, and the final borrowing base may be lower than the level recommended by the agent for the bank group. As we have borrowed all available capacity under our current borrowing base, if our borrowing base were adjusted downward, we would be required to pay down amounts outstanding under our revolving credit sub-facility to reduce our level of borrowing, or we must pledge other natural gas and oil properties as

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collateral. We do not currently have any substantial properties which could serve as additional collateral, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility. If funding is not available from internally generated cash flow, additional borrowings from or investments by EGC in the Company when needed, or is available only on unfavorable terms, it could adversely affect our development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.

Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By consummating acquisitions only in the Gulf of Mexico and the U.S. Gulf Coast, our lack of diversification may:

In addition, the geographic concentration of our properties in the Gulf of Mexico and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:

During the 2008 hurricane season, production from certain of our properties was reduced as a result of damage to third party pipelines caused by two hurricanes. The hurricane damage limited our ability to sell our production from certain properties for extended periods of time during the third and fourth quarters of 2008. If mechanical problems, storms or other events were to curtail a substantial portion of the production, such a curtailment could have a material adverse effect on our business, financial condition, results of operations and cash flows. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “— Our insurance may not protect us against all of the operating risks to which our business is exposed.”

Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

We engage in exploration and development drilling activities, which are inherently risky. These activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions such as hurricanes and tropical storms in the Gulf of Mexico, cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.

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Our business involves a variety of operating risks, which include, but are not limited to:

If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:

Our offshore operations involve special risks that could affect our operations adversely.

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.

Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.

Our insurance may not protect us against all of the operating risks to which our business is exposed.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, including with respect to commodity prices

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such as for oil and natural gas, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events like the terrorist attacks on September 11, 2001, Hurricanes Ivan, Katrina, Rita, Gustav and Ike, and the April 20, 2010 Deepwater Horizon incident, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered damage from Hurricanes Ivan, Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is severe, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, we do not intend to put in place business interruption insurance due to its high cost. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

Weather Based Insurance Linked Securities may not payout in case of a hurricane or may not fully cover damage.

We utilize Weather Based Insurance Linked Securities (“Securities”) to supplement our windstorm insurance coverage to mitigate potential loss to our most valuable oil and gas properties from hurricanes in the Gulf of Mexico. These Securities are generally structured to provide for payments of negotiated amounts should a hurricane having a pre-established category pass within specific pre-defined areas encompassing our oil and gas producing fields. While these Securities are meant to provide some excess windstorm coverage, there can be no certainty that these Securities will meet the payout criteria even if there is substantial damage by a hurricane of a lower category than that specified in the Securities. In addition, the payment made may not be sufficient to cover any actual damage incurred from a storm.

Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

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Market conditions or transportation impediments may hinder access to oil and gas markets, delay production or increase our costs.

Market conditions (including with respect to commodity prices such as for oil and natural gas), the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, market access depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.

Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We currently do not have leases expiring in fiscal years 2016 or 2017, but leases covering approximately 21% of our net acreage could potentially expire in fiscal year 2018.

Our drilling plans for areas not currently held by production are subject to change based upon various factors, including factors that are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.

We are not the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We operated approximately 88% of our proved reserves (including approximately 24% attributable to the South Pass 49 field operated by Energy XXI) at June 30, 2015. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

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Each of these factors, including others, could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

We are exposed to trade credit risk in the ordinary course of our business activities.

We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. From time to time, the availability of credit is more restrictive. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.

We sell the majority of our production to three customers.

Chevron, ConocoPhillips and Shell each accounted for approximately 58%, 20%, and 20% respectively, of our total oil and natural gas revenues during the year ended June 30, 2015. Our inability to continue to sell our production to Chevron, ConocoPhillips or Shell, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.

Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.

Additionally, if John D. Schiller, Jr. ceases to be the chief executive officer of Energy XXI (except as a result of his death or disability) and a reasonably acceptable successor is not appointed within 180 days, the lenders of our revolving credit facility could declare amounts outstanding thereunder immediately due and payable. Such an event could have a material adverse effect on our business and operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices

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for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.

Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.

We enter into derivative contracts to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use a combination of crude oil and natural gas put, swap and collar arrangements to mitigate the volatility of future oil and natural gas prices received on our production.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial decrease in our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

During periods of declining commodity prices, our commodity price derivative positions increase, which increases our counterparty exposure.

Deepwater operations present special risks that may adversely affect the cost and timing of reserve development.

Currently, we own interests in one undeveloped lease in the deepwater Gulf of Mexico and we have a non-operated interest in one developed lease. We may evaluate additional activity in the deepwater Gulf of Mexico in the future. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

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Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.

In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, BSEE and BOEM, each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have also implemented and enforced new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added and more stringent regulatory restrictions in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill response plans could adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are developing and implementing new, more restrictive requirements such as, for example, the 2013 amendments to the federal Workplace Safety Rule regarding the utilization of a more comprehensive safety and environmental management system, (“SEMS”), which amended rule is sometimes referred to as SEMS II, and, more recently, the April 17, 2015 proposed rulemaking by the BSEE that would impose more stringent requirements with respect to use of blow out preventers and related well control equipment.

Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill incidents were to occur in the future, the United States or other countries could elect again to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development. We cannot predict the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

Further, the deepwater areas of the Gulf of Mexico (as well as international deepwater locations) lack the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite our oil spill response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident. The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.

The construction and operation of energy projects require numerous permits and approvals from governmental agencies. In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years. We may not be able to obtain all necessary permits and approvals or obtain them in a timely manner, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse changes in the interpretation of existing permits and approvals, and these may create a risk of expensive delays or loss of value if a project is unable to proceed as planned due to changing requirements or local opposition.

Our operations are subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.

As described in more detail below, our business activities are subject to regulation by multiple federal, state and local governmental agencies. Our historical and projected operating costs reflect the recurring costs

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resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. Additional proposals and proceedings that affect the oil and gas industries are regularly considered by Congress, the states, regulatory commissions and agencies, and the courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business; however, additions or enhancements to the regulatory burden on our industry generally increase the cost of doing business and affect our profitability.

Our oil and gas exploration, production, and related operations are subject to extensive rules and regulations promulgated by federal, state, and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.

All of the jurisdictions in which we operate generally require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain jurisdictions also limit the rate at which oil and gas can be produced from our properties.

FERC regulates interstate natural gas transportation rates and terms of service, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. FERC has implemented regulations establishing an indexing methodology for interstate transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.

Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and are therefore not subject to FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, however, and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. If FERC were to consider the status of an individual facility and determine that the facility and/or services

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provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.

State regulation of gathering facilities includes safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. State and local regulation may cause us to incur additional costs or limit our operations and can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:

Failure to comply with these laws and regulations may result in:

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure shareholders that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.

Under certain environmental laws that impose strict, joint and several liability, we could be held liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, and regardless of whether current or prior operations were conducted in compliance with all applicable laws and consistent with accepted standards of practice at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.

We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

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Rate regulation may not allow us to recover the full amount of increases in our costs.

We have ownership interests in oil pipelines that are subject to regulation by FERC. Rates for service on our system are set using FERC’s price indexing methodology. The indexing method currently allows a pipeline to increase its rates by a percentage factor equal to the change in the producer price index for finished goods plus 2.65 percent. When the index falls, we are required to reduce rates if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs.

FERC’s indexing methodology is subject to review every five years. The current or any revised indexing formula could hamper our ability to recover our costs because: (1) the indexing methodology is tied to an inflation index; (2) it is not based on pipeline-specific costs; and (3) it could be reduced in comparison to the current formula. Any of the foregoing would adversely affect our revenues and cash flow. FERC could limit our pipeline’s ability to set rates based on its costs, order our pipelines to reduce rates, require the payment of refunds or reparations to shippers, or any or all of these actions, which could adversely affect our financial position, cash flows, and results of operations. If FERC’s ratemaking methodology changes, the new methodology could also result in tariffs that generate lower revenues and cash flow.

Based on the way our oil pipelines are operated, we believe that the only transportation on our pipelines that is subject to the jurisdiction of FERC is the transportation specified in the tariff we have on file with FERC. We cannot guarantee that the jurisdictional status of transportation on our pipelines and related facilities will remain unchanged, however. Should circumstances change, then currently non-jurisdictional transportation could be found to be FERC-jurisdictional. In that case, FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs, and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, results of operations and financial condition.

If our tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues.

Shippers on our pipelines are free to challenge, or to cause other parties to challenge or assist others in challenging, our existing or proposed tariff rates. If any party successfully challenges our tariff rates, the effect would be to reduce revenues.

Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.

FERC, the FTC and the CFTC hold statutory authority to regulate certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these commodities, we are required to observe and comply with these anti-fraud and anti-manipulation regulations. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.

We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.

Our management has identified material weaknesses in our internal control over financial reporting as of June 30, 2015. Further, we have determined that control deficiencies existed with respect to certain aspects of our historical financial reporting subsequent to the Merger, and accordingly, we have concluded that our reports subsequent to the Merger on disclosure controls and procedures may not have been correct and reports subsequent to the Merger on internal control over financial reporting and changes in internal control over financial reporting may have been incorrect. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

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We did not maintain properly designed controls over the contemporaneous formal documentation that we had prepared subsequent to the Merger to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program. Specifically, the controls in place subsequent to the Merger relating to the documentation of hedge designations were not properly designed to provide reasonable assurance that these derivative contracts would be properly recorded and disclosed in the financial statements in accordance with U.S. GAAP. As a result subsequent to the Merger, our controls failed to detect that our formal hedge documentation did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Effective June 30, 2015, management discontinued the use of hedge accounting on all derivative contracts and does not expect the material weakness associated with hedge accounting to recur. If, in the future, we were to begin to designate our derivatives as hedges we would need to enhance our controls regarding consideration of all sources of ineffectiveness.

In addition, we recently learned that, in 2007, 2009 and 2014, the Chief Executive Officer of our parent company Energy XXI Ltd borrowed funds from personal acquaintances or their affiliates, certain of whom provided the Company with services. We also learned that Norman Louie, one of the directors of our parent company, made a personal loan to Mr. Schiller in 2014 before Mr. Louie became a director of our parent. At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of June 30, 2015, owned a majority interest in Energy XXI M21K, in which our parent owned a 20% interest (and purchased the remaining 80% interest subsequent to June 30, 2015), and 6.3% of our parent’s common stock. The loans made in 2014 are still outstanding. Since Mr. Schiller did not disclose the personal loans before they were made, our parent’s board of directors has determined that he did not comply with the procedural requirements of the Company’s Code of Business Conduct and Ethics. Upon learning of Mr. Schiller’s personal loans from affiliates of service providers, our parent’s board of directors engaged independent legal counsel to conduct an internal investigation, with the assistance of outside forensic accountants, to review these loans and vendor procurement processes across the organization, including EPL. Our parent’s board of directors is still reviewing the results of the internal investigation. Although the internal investigation has not uncovered any illegal activity or any impact on parent or EPL’s financial reporting or financial statements, we have concluded this non-compliance to be a material weakness in its control environment given the leadership position of this officer, the visibility and importance of his actions to the Company’s overall system of controls and the significance with which the Company views this nondisclosure. As part of its review, our parent’s board of directors has begun the process of designing and implementing additional controls and procedures, including, but not limited to, strengthening the vendor procurement procedures across the organization including EPL to address any potential conflicts of interest that could arise from Mr. Schiller’s personal loans; revising our parent’s Code of Business Conduct and Ethics to explicitly ban any such personal loans in the future; and implementing an enhanced comprehensive training program on our parent’s Code of Business Conduct and Ethics.

If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner, either of which could subject us to litigation and regulatory enforcement actions.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.

The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries

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and certain onshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40% to 45% from 2012 emission levels by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. As the number of emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by President Obama on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity

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instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

Cyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimated quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to extract oil and gas in increasingly difficult physical environments, such as ultra-deep trend, and global competition for oil and gas resources make certain information more attractive to thieves.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. Certain countries, including China, Russia and Iran, are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. SCADA-based systems are potentially more vulnerable to cyber-attacks due to the increased number of connections with office networks and the internet.

Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:

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Although to date we have not experienced any losses relating to cyber-attacks, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

The Budget for Fiscal Year 2016 sent to Congress by President Obama on February 2, 2015, among other proposed legislation, contains recommendations that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The information contained in Part I, Item 1, “Business” of this Form 10-K is incorporated herein by reference.

Item 3. Legal Proceedings

The information contained in Note 14, “Commitments and Contingencies” in the consolidated financial statements in Part II, Item 8 of this Form 10-K is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Following the effective date of the Merger, we became an indirect, wholly owned subsidiary of Energy XXI and there is no longer a trading market for EPL common stock. As a result of the Merger, our common stock was suspended from trading on June 4, 2014 and removed from listing and registration on the New York Stock Exchange (the “NYSE”) on July 15, 2014.

Prior to the Merger, our common stock was listed on the NYSE under the symbol “EPL.” The following table sets forth, for the periods indicated, the range of the high and low sales prices of our common stock as reported by the NYSE.

		High				Low
		($)				($)
2013
First Quarter			29.18				22.53
Second Quarter			35.14				26.05
Third Quarter			38.32				28.75
Fourth Quarter			42.64				25.00
2014
First Quarter			39.26				25.18
Second Quarter (through June 3, 2014)			39.31				36.85

On June 3, 2014, the last reported sales price of our common stock on the NYSE was $37.73 per share.

We have not paid cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including the 8.25% senior notes due 2018 (the “8.25% Senior Notes”) issued under an indenture dated February 14, 2011 (the “2011 Indenture”), place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our board of directors.

Not applicable due to reduced disclosure format allowed for certain wholly-owned subsidiaries pursuant to General Instruction I(1)(a) and (b) of Form 10-K.

The following discussion and analysis should be read in conjunction with Item 8, “Financial Statements and Supplementary Data” of this Form 10-K. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Known material factors that could cause or contribute to such differences include those discussed under Part I, Item 1A “Risk Factors” in this Form 10-K.

Restatement of Previously Issued Consolidated Financial Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations have been updated to reflect the effects of the restatement described in Note 17 — Restatement of Previously Issued Consolidated Financial Statements of Notes to Consolidated Financial Statements in this Form 10-K. We have also included our restated financial statements for the three unaudited quarters of fiscal 2015 following our fiscal year 2015 financial statements in Item 8, “Financial Statements and Supplementary Data” in this Form 10-K. In addition, we have included a discussion of restated revenues, related costs and income tax expense for the three unaudited quarters of 2015 following the discussion of our results of operations for our year ended June 30, 2015 compared to the year ended December 31, 2013.

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In connection with preparing this Form 10-K, we determined that the contemporaneous formal documentation that we had prepared subsequent to the Merger to support our designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment applied subsequent to the Merger, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.

This restatement, which impacts periods subsequent to the Merger, primarily reflects the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) to gain (loss) on derivative financial instruments in earnings and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment as described above. For the quarters ending December 31, 2014 and March 31, 2015, the restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. While these non-cash adjustments impact revenues and net income (loss) for each period, as well as total stockholders’ equity, these adjustments do not impact the economics of the hedge transactions nor do they affect our liquidity.

Overview

We were incorporated as a Delaware corporation on January 29, 1998. We are an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf (the “GoM shelf”) focusing on state and federal waters offshore Louisiana, which we consider our core area. As of June 30, 2015, we had estimated proved reserves of 57.2 Mmboe, of which 67% were oil and 76% were proved developed. Of these proved developed reserves, 70% were oil reserves.

On June 3, 2014, Energy XXI, EGC, Merger Sub, and EPL, completed the transactions contemplated by 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. 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 the Company is determined by Energy XXI’s Board of Directors. For the year ended June 30, 2015, our capital expenditures totaled approximately $271 million, of which approximately $186 million was spent on development of core properties and $27 million on exploration of core properties and $58 million on other assets. Our fiscal year 2016 capital budget is approximately $26 million, excluding potential capitalized general and administrative expenses. The budgeted capital is allocated to development activities, which are geared toward the improvement of existing production, the continued development of core fields, and the performance of necessary plugging, abandonment and other decommissioning activities.

Disposition

On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5%

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overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $68.9 million.

Known Trends and Uncertainties

Commodity Price Volatility.  Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil prices declined significantly during fiscal year 2015, and our ability to maintain current production levels could be impacted by continued downward pressure on oil prices. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from July 1, 2014 to June 30, 2015 ranged from a high of $105.34 to a low of $43.46, a decrease of 58.7%, and the NYMEX natural gas price per MMBtu for the period July 1, 2014 to June 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 22, 2015, the spot market price for WTI was $45.83. The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. If we experience sustained periods of low prices for oil and natural gas, it will likely have a further material adverse effect on our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.

Decreasing Service Costs.  We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods. Jack-up rig rates, for example, have fallen by 35 – 50% in recent months and other service providers are similarly cutting their rates.

Ceiling Test Write-down.  For the second, third and fourth quarters of our fiscal year ended June 30, 2015, we recognized ceiling test write-downs of our oil and natural gas properties of $690.3 million, $404.3 million and $584.2 million, respectively. The write-downs did not impact our cash flows from operating activities but did increase our net loss and reduce stockholders’ equity. Further ceiling test write-downs may be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows. Based on 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 September 30, 2015, we presently expect to incur further impairment of $300 million to $500 million in the first fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues beyond first fiscal quarter of 2016, we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.

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

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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 requires payment of the supplemental bonding amount in three equal installment 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. We currently maintain approximately $58.3 million in lease and/or area bonds issued to the BOEM and approximately $122.5 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $180.8 million, with an annual premium expense of $2.7 million. We are undertaking a number of initiatives to mitigate our potential additional bonding requirements resulting from any waiver disqualifications and any forthcoming requirement from the BOEM and to limit the amount of additional required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date, by accounting for recent asset divestitures and consequential reduction in related bonding requirements such as the June 2015 sale of our interest in the East Bay field, and by counting our existing bonds and letters of credit with third parties against the BOEM’s various bonding requests. However, with respect to our existing bonds and letters of credit with third parties, we can provide no assurance that the BOEM will consider them when determining the total value of additional financial assurances and/or bonding we must provide. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements.

Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, in addition to the Draft Guidance describing revised supplemental bonding procedures that may be used by the BOEM, 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 or any other changes to the BOEM’s current NTL supplemental bonding requirements or supplemental bonding regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Please read “Risk Factors — We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”

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

We have contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the

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petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.

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

Results of Operations

The Merger resulted in EPL becoming an indirect, wholly owned subsidiary of Energy XXI. Therefore, in the preparation of our financial statements, we have applied “pushdown” accounting, based on guidance from the Securities and Exchange Commission (“SEC”). Pushdown accounting refers to the use of the acquiring entity’s basis of accounting in the preparation of the acquired entity’s financial statements. As a result, our separate financial statements reflect the new basis of accounting recorded by Energy XXI upon acquisition. As such, in accordance with GAAP, due to our new basis of accounting, our financial statements include a black line denoting that our financial statements covering periods prior to the date of the Merger are not comparable to our financial statements as of and subsequent to the date of the Merger. References to the “Predecessor Company” refer to reporting dates of the Company through June 3, 2014, reflecting results of operations and cash flows of the Company prior to the Merger on our historical accounting basis; subsequent thereto, the Company is referred to as the “Successor Company,” reflecting the impact of pushdown accounting and the results of operations and cash flows of the Company subsequent to the Merger.

Energy XXI follows the “full cost” method of accounting for its oil and gas producing activities, while we had historically followed the “successful efforts” method of accounting. Subsequent to the Merger, we converted our accounting method from successful efforts to the full cost method of accounting to be consistent with Energy XXI’s method of accounting pursuant to SEC guidance, which requires a reporting entity that follows the full cost method to apply that method to all of its operations and to the operations of its subsidiaries. Under GAAP, a change in accounting method is generally required to be applied retroactively in order to provide comparable historical period information to users of financial statements. However, due to the new basis of accounting established as a result of the Merger transaction and pushdown accounting, our financial statements are no longer comparable to those of prior periods and we have applied the full cost method of accounting on a prospective basis from the date of the Merger.

Energy XXI has a fiscal year end of June 30, while we historically had a fiscal year end of December 31. Subsequent to the Merger, we changed our fiscal year end to June 30 to be consistent with Energy XXI. Therefore, these financial statements include audited statements of operations, cash flows and stockholders’ equity using the successful efforts method of accounting applied to the historical basis in our assets and liabilities for the five months and three days ended June 3, 2014 and audited statements of operations, cash flows and stockholders’ equity using the full cost method of accounting applied to EPL’s new basis in its assets and liabilities established in the Merger transaction for the twenty-seven days ended June 30, 2014, with a black line between the periods denoting that they are not comparable.

Prior to the Merger, we used the successful efforts method of accounting for oil and natural gas producing activities. Costs to acquire mineral interests in oil and natural gas properties, to drill and complete exploratory wells with found proved reserves, and to drill and complete development wells were capitalized. Exploratory drilling costs were initially capitalized, but charged to expense if and when a well was determined not to have reserves in commercial quantities. Geological and geophysical costs were charged to expense as incurred. Leasehold acquisition costs were capitalized as unproved properties. If proved reserves were discovered on undeveloped leases, the related leasehold costs were transferred to proved properties and amortized using the units of production method. For individual unevaluated properties with capitalized costs below a threshold amount, we allocated capitalized costs to earnings generally over the primary lease terms. Properties that were subject to amortization and those with capitalized costs greater than the threshold amount were assessed for impairment periodically. Capitalized costs of producing oil and natural gas properties were depreciated and depleted by the units-of-production method.

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Subsequent to the Merger, we adopted the full cost method of accounting for exploration and development activities. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

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

As a result of pushdown accounting in connection with the Merger, the Predecessor Company’s operations are deemed to have ceased on June 3, 2014 and the Successor Company began operations as of that date. In the following discussion, references to the combined operations for the six months ended June 30, 2014 combine the periods from January 1, 2014 through June 3, 2014 (reflecting the operations of the Predecessor Company) with the period from June 4, 2014 through June 30, 2014 (reflecting the operations of the Successor Company). The combined results of operations for the six months ended June 30, 2014 represent a non-GAAP financial measure due to the application of pushdown accounting and conversion to the full cost method of accounting for exploration and development activities. In addition, the consolidated financial statements of the Successor Company are not comparable to those of the Predecessor Company. However, the comparability of certain components of our operating results and key operating performance measures was not significantly impacted by the Merger, specifically those related to production, average oil and natural gas selling prices, revenues and lease operating expenses. Therefore, we believe that presenting the Successor Company’s results of operations and cash flows with those of the Predecessor Company on a combined basis for the six months ended June 30, 2014 is useful when analyzing certain measures of our performance. For those items that are not comparable, we have included additional analysis to supplement the discussion.

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Year Ended June 30, 2015 Compared to Year Ended December 31, 2013

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

		Year Ended June 30, 2015				Year Ended December 31, 2013
Net production (per day):
Oil (Bbls)			18,289				16,938
Natural gas (Mcf)			43,734				32,863
Total (Boe)			25,578				22,415
Average sales prices:
Oil (per Bbl)		$	67.66			$	104.01
Natural gas (per Mcf)			3.14				3.81
Gain on derivative financial instruments (per Boe)			4.29				—
Total (per Boe)			58.04				84.18
Oil and natural gas revenues (in thousands):
Oil		$	451,676			$	643,033
Natural gas			50,113				45,710
Gain on derivative financial instruments			40,082				—
Total			541,871				688,743
Average costs (per Boe):
LOE		$	22.68			$	20.27
Taxes, other than on earnings			0.87				1.40
General and administrative (“G&A”) expenses			3.78				3.44
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil		$	(224,720	)
Changes in production volumes of oil			33,363
Total decrease in oil sales		$	(191,357	)
Changes in prices of natural gas		$	(8,001	)
Changes in production volumes of natural gas			12,404
Total increase in natural gas sales		$	4,403

Overview

Our operating results for the year ended June 30, 2015 compared to the year ended December 31, 2013, reflect an 8% increase in oil production and a 33% increase in natural gas production, resulting in a 14% increase in our overall production volumes. Our product mix for the year ended June 30, 2015 was 72% oil (including natural gas liquids) compared to 76% for the year ended December 31, 2013.

Revenue

		Year Ended June 30, 2015				Year Ended December 31, 2013				$ Change				% Change
		(in thousands)				(in thousands)
Oil and natural gas revenues		$	501,789			$	688,743			$	(186,954	)			-27	%
Gain on derivative financial instruments			40,082				—				40,082

For the year ended June 30, 2015, our oil and natural gas revenues decreased 27% as compared to the year ended December 31, 2013, due primarily to a 35% decrease in average selling prices for our oil partially offset by an 8% increase in oil production. Additionally, we had a 33% increase in natural gas production and partially offset by an 18% decrease in average selling prices for natural gas for the year ended June 30, 2015, as compared to the year ended December 31, 2013.

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Our overall average selling prices decreased by 31% for the year ended June 30, 2015 when compared to the year ended December 31, 2013. Average crude oil prices decreased $36.35 per barrel in fiscal 2015, resulting in lower revenues of approximately $224.7 million. Average natural gas prices decreased $0.67 per Mcf in fiscal 2015, resulting in lower revenues of approximately $8.0 million. Our hedging activities resulted in higher revenues of $40.1 million or $4.29 per BOE for the year ended June 30, 2015. Prior to the Merger, the Predecessor Company recorded gain (loss) on derivative financial instruments in Other income (expense).

Operating Expenses

Our operating expenses primarily consist of the following:

		Year Ended June 30, 2015				Year Ended December 31, 2013				$ Change				% Change
		(in thousands)
LOE		$	211,699			$	165,841			$	45,858				28	%
Exploration expenditures and dry hole costs(1)			—				26,555				NM
Impairment of oil and natural gas properties(1)			1,678,804				2,937				NM
Goodwill impairment			329,293				—				NM
DD&A, including accretion expense(1)			338,353				228,658				NM
G&A expenses			35,324				28,137				7,187				26	%
Taxes, other than on earnings			8,126				11,490				(3,364	)			-29	%
Other			18				34,942				(34,924	)			NM

NM — Not meaningful.

LOE increased for the year ended June 30, 2015, compared to the year ended December 31, 2013, primarily due to the acquisition of the EI Interests and SP49 Interests. LOE for the year ended June 30, 2015 also included non-routine costs associated with pipeline maintenance in two fields in addition to other non-routine workover and other expenses.

Under the full cost method, 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 amount of the discounted cash flows. As a result of our ceiling test during the year ended June 30, 2015, we recognized ceiling test impairments of our oil and natural gas properties totaling $1.7 billion. Impairments for the year ended December 31, 2013 were determined under the successful efforts method and primarily related to reservoir performance at a gas well in one of our smaller producing fields. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value during the year ended December 31, 2013.

During the year ended June 30, 2015, we recorded a non-cash goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero as of September 30, 2014. At September 30, 2014, we performed a goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since June 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than the carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital used to estimate fair value, both of which adversely impacted the fair value of our reserves. Therefore, we performed

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the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at September 30, 2014.

G&A expenses increased for the year ended June 30, 2015, as compared to the year ended December 31, 2013, primarily due to the cost of services allocated to us pursuant to an intercompany services and cost allocation agreement with an affiliate, Energy Services, which we entered into in connection with the Merger.

During the year ended December 31, 2013, we had other operating expenses of $34.9 million, primarily due to loss on abandonment activities totaling $27.2 million which primarily reflected an increase of $20.8 million in our asset retirement obligation liability related to our non-operated deepwater properties. Other operating expenses also included amortization expense related to our weather derivative of $8.0 million for the year ended December 31, 2013.

Other Income and Expense

Interest expense decreased approximately $1.1 million for the year ended June 30, 2015, as compared to the year ended December 31, 2013 due primarily to a decrease in our effective interest rate on the 8.25% Senior Notes from 9.1% to 5.8%, reflecting the impact of the fair value adjustment to the carrying amount of the 8.25% Senior Notes recorded in pushdown accounting. This decrease was partially offset by an increase in interest expense on our revolving credit sub-facility and our intercompany promissory note during fiscal year 2015.

Other income (expense) in the year ended December 31, 2013 included a net loss on derivative instruments of $32.4 million consisting of a loss of $20.9 million due to the change in fair value of derivative instruments which were to be settled in the future and a loss of $11.5 million on derivative instruments settled during the period primarily from the impact of higher oil prices on our oil fixed-price swaps. The Successor Company classifies gain (loss) on derivative financial instruments as a component of revenue.

Income Taxes

For the year ended June 30, 2015, we recorded income tax benefit of $459 million. Excluded from the income tax benefit is the effect of the goodwill impairment charge recorded in the first quarter of fiscal 2015. The effective income tax/(benefit) rate for the year ended June 30, 2015 was (21.7)% as compared to 36.8% for the year ended December 31, 2013. The variance in the tax rate is primarily due to the valuation allowance recorded as of June 30, 2015. In light of changes in our expectations regarding our future taxable income, consistent with the results of operations for the current year (heavily affected by impairments), we recorded a valuation allowance of $189.6 million at June 30, 2015. See Note 12, “Income Taxes” in of the consolidated financial statements in Part II, Item 8 of this Form 10-K for additional information.

Restated Quarterly Comparisons

The following table and subsequent section discuss the effect of the restatement for impacted line items on the consolidated statement of operations for the first three quarters in fiscal years 2015. Amounts related to derivatives previously classified in accumulated other comprehensive income (loss) have been reclassified to gain (loss) on derivative financial instruments. The total impact to the income statement is shown in “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”

		For the Quarter Ended
		September 30, 2014				December 31, 2014				March 31, 2015
Revenue – Oil and natural gas:
As previously reported		$	173,720			$	156,070			$	87,253
Adjustments to revenue – oil and natural gas			(1,839	)			(23,237	)			(1,830	)
As restated			171,881				132,833				85,423

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		For the Quarter Ended
		September 30, 2014				December 31, 2014				March 31, 2015
(Loss) gain on derivative financial instruments:
As previously reported		$	(30	)		$	(26	)		$	(579	)
Adjustments to (loss) gain on derivative financial instruments			21,887				22,288				(1,634	)
As restated			21,857				22,262				(2,213	)
Total Revenue:
As previously reported			174,109				156,613				87,253
Adjustments to total revenue			20,018				(975	)			(4,043	)
As restated			194,127				155,638				83,210
Net Loss:
As previously reported			(319,371	)			(449,478	)			(310,517	)
Adjustments to net loss			13,015				(5,134	)			14,884
As restated			(306,356	)			(454,612	)			(295,633	)

Three months ended September 30, 2014 compared with three months ended September 30, 2013

Revenues

The restatement adjustment increased our consolidated revenues for the three months ended September 30, 2014 by $20.0 million. Our consolidated revenues increased $10.1 million in the first quarter of fiscal 2015 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to the gain on derivative financial instruments and higher oil and natural gas sales volumes, partially offset by lower oil sales prices. Average oil prices decreased $11.82 per barrel in the first quarter of fiscal 2015, resulting in lower revenues of $19.0 million. Average natural gas prices increased $0.28 per Mcf during the first quarter of fiscal 2015 resulting in higher revenues of $0.9 million. Our hedging activities more than offset the impact of the decrease in oil prices resulting in higher revenues of $21.9 million or $9.69 per BOE. The gain on derivatives for the three months ended September 30, 2014 reflects a gain on settlements of our derivative contracts of approximately $1.09 per barrel of oil.

Income Tax Expense

The restatement adjustment increased our income tax expense for the three months ended September 30, 2014 by $7.0 million. Restated income tax expense increased by $13.9 million for the three months ended September 30, 2014 compared to the three months ended September 30, 2013. Our effective income tax rate for the three months ended September 30, 2014 was 35.9%, excluding the impact of the goodwill impairment charge during the period, which is not deductible for income tax purposes. Our effective income tax rate for the three months ended September 30, 2013 was 44.4%. The decrease in our effective income tax rate is primarily related to our estimated state income taxes.

Three months ended December 31, 2014 compared with three months ended December 31, 2013

Revenues

The restatement adjustment decreased our consolidated revenues for the three months ended December 31, 2014 by $1.0 million. Our consolidated revenues increased $13.0 million in the second quarter of fiscal 2015 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher oil sales volumes and gain on derivative financial instruments, partially offset by lower commodity sales prices. Average oil prices decreased $23.57 per barrel in the second quarter of fiscal 2015, resulting in lower revenues of $32.8 million. Average natural gas prices decreased $0.39 per Mcf during the second quarter of fiscal 2015, resulting in lower revenues of $1.0 million. Our hedging activities partially offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $22.3 million or $9.71 per BOE. 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.

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Costs and Expenses and Other (Income) Expense

The restatement adjustment increased our costs and expenses for the three months ended December 31, 2014 by $7.4 million. Restated costs and expenses increased $728.1 million in the second quarter of fiscal 2015 as compared to the same period in the prior fiscal year, principally due to the restated impairment of oil and gas properties of $690.3 million.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at December 31, 2014, we recognized a restated ceiling test impairment of our oil and natural gas properties totaling $690.3 million. The restatement adjustment increased our impairment of oil and natural gas properties during the three months ended December 31, 2014 by $7.4 million.

Income Tax Expense

The restatement adjustment increased our income tax benefit for the three months ended December 31, 2014 by $3.3 million. Restated income tax benefit increased $245.1 million in the second quarter of fiscal 2015 compared to the three months ended December 31, 2013. The effective income tax/(benefit) rate for the second quarter of fiscal 2015 was (35.6)% as compared to (32.2)% for the three months ended December 31, 2013. The increase in the tax rate is primarily due to two elements: (i) the increase in pre-tax net loss and (ii) an increase in common permanent difference items.

Six months ended December 31, 2014 compared with six months ended December 31, 2013

Revenues

The restatement adjustment increased our consolidated revenues for the six months ended December 31, 2014 by $19.0 million. Our restated consolidated revenues increased $23.2 million in the first six months of fiscal 2015 as compared to the six months ended December 31, 2013. Higher revenues were primarily due gain on derivative financial instruments and higher oil sales volumes, partially offset by lower oil sales prices. Average oil prices decreased $18.28 per barrel in the first six months of fiscal 2015, resulting in lower revenues of $54.8 million. Average natural gas prices decreased $0.04 per Mcf in the first six months of fiscal 2015, resulting in lower revenues of $0.2 million. Our hedging activities partially offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $44.1 million or $9.70 per BOE. The gain on derivatives for the six months ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $8.77 per barrel of oil.

Costs and Expenses and Other (Income) Expense

The restatement adjustment increased our costs and expenses for the six months ended December 31, 2014 by $7.4 million. Restated costs and expenses increased $1,061.6 million in the second quarter of fiscal 2015 as compared to the same period in the prior fiscal year, principally due to the restated impairment of oil and gas properties of $690.3 million and the goodwill impairment charge of $329.3 million.

Income Tax Expense

The restatement adjustment decreased our income tax benefit for the six months ended December 31, 2014 by $3.8 million. Restated income tax benefit increased by $231.3 million in the first six months of fiscal 2015 compared to the six months ended December 31, 2013. The effective income tax/(benefit) rate (excluding the discrete item from pre-tax book loss) for the first six months of fiscal 2015 was (35.5)% as compared to (33.6)% for the six months ended December 31, 2013. The increase in the tax rate is primarily due to two elements: (i) the increase in pre-tax net loss and (ii) an increase in common permanent difference items.

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Three months ended March 31, 2015 compared with three months ended March 31, 2014

Revenues

The restatement adjustment decreased our consolidated revenues for the three months ended March 31, 2015 by $4.0 million. Our consolidated revenues decreased $76.3 million in the third quarter of fiscal 2015 as compared to the three months ended March 31, 2014. Lower revenues were primarily due to lower commodity sales prices, partially offset by higher sales volumes. Average oil prices decreased $52.90 per barrel in the third quarter of fiscal 2015, resulting in lower revenues of $77.4 million. Average natural gas prices decreased $2.42 per Mcf during the third quarter of fiscal 2015, resulting in lower revenues of $6.0 million. Our hedging activities resulted in lower revenues of $2.2 million or $0.96 per BOE.

Costs and Expenses and Other (Income) Expense

The restatement adjustment decreased our costs and expenses for the three months ended March 31, 2015 by $26.8 million. Restated costs and expenses increased $436.2 million in the third quarter of fiscal 2015 as compared to the three months ended March 31, 2014, principally due to the restated impairment of oil and gas properties of $404.3 million.

At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at March 31, 2015, we recognized a restated ceiling test impairment of our oil and natural gas properties totaling $404.3 million. The restatement adjustment decreased our impairment of oil and natural gas properties during the three months ended March 31, 2015 by $26.6 million.

Income Tax Expense

The restatement adjustment decreased our income tax benefit for the three months ended March 31, 2015 by $8.5 million. We recorded restated income tax benefit of $182.0 million in the third quarter of fiscal 2015 compared to income tax expense of $7.6 million in the three months ended March 31, 2014. The effective income tax (benefit) rate for the third quarter of fiscal 2015 was (38.1%) as compared to 36.4% for three months ended March 31, 2014. The increase in the tax rate is primarily due to an increase in common permanent difference items.

Nine months ended March 31, 2015 compared with nine months ended March 31, 2014

Revenues

The restatement adjustment increased our consolidated revenues for the nine months ended March 31, 2015 by $15.0 million. Our restated consolidated revenues decreased $53.1 million in the first nine months of fiscal 2015 as compared to the nine months ended March 31, 2014. Lower revenues were primarily due to lower commodity sales prices partially offset by higher sales volumes and gain on derivative financial instruments. Average oil prices decreased $29.27 per barrel in the first nine months of fiscal 2015, resulting in lower revenues of $130.6 million. Average natural gas prices decreased $0.83 per Mcf during the first nine months of fiscal 2015, resulting in lower revenues of $6.9 million. Our hedging activities partially offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $41.9 million or $6.12 per BOE. The gain on derivatives for the nine months ended March 31, 2015 reflects a gain on settlements and monetization of our derivative contracts of approximately $5.97 per barrel of oil.

Costs and Expenses and Other (Income) Expense

The restatement adjustment decreased our costs and expenses for the nine months ended March 31, 2015 by $19.4 million. Restated costs and expenses increased $1,497.8 million in the first nine months of fiscal 2015 as compared to the nine months ended March 31, 2014, principally due to the impairment of oil and gas properties and the impairment of goodwill.

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As a result of our ceiling test at March 31, 2015, we recognized a restated ceiling test impairment of our oil and natural gas properties totaling $1,094.6 million during the nine months ended March 31, 2015. The restatement adjustment decreased our impairment of oil and natural gas properties during the nine months ended March 31, 2015 by $19.4 million.

Income Tax Expense

The restatement adjustment decreased our income tax benefit for the nine months ended March 31, 2015 by $12.3 million. We recorded restated income tax benefit of $420.0 million in the first nine months of fiscal 2015 compared to income tax expense of $0.9 million in the nine months ended March 31, 2014. The effective income tax (benefit) rate (excluding the discrete item from pre-tax book loss) for the first nine months of fiscal 2015 was (36.6%) as compared to 101.3% for the nine months ended March 31, 2014. The decrease in the tax rate is primarily due to changes in common permanent difference items.

Results of Operations — Restated Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

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

		Period from June 4, 2014 through June 30, 2014 (Restated)				Period from January 1, 2014 through June 3, 2014				Non-GAAP Combined Results for the Six Months Ended June 30, 2014 (Restated)				Six Months Ended June 30, 2013
Net production (per day):
Oil (Bbls)			19,113				16,922				17,285				17,591
Natural gas (Mcf)			26,410				26,502				26,487				34,352
Total (Boe)			23,515				21,339				21,700				23,316
Average sales prices:
Oil (per Bbl)		$	100.48			$	99.73			$	99.87			$	106.79
Natural gas (per Mcf)			4.62				4.98				4.92				3.86
Loss on derivative financial instruments (per BOE)			(15.71	)			—				(2.82	)			—
Total (per Boe)			71.15				85.28				82.74				86.25
Oil and natural gas revenues (in thousands):
Oil		$	57,613			$	254,827			$	312,440			$	340,003
Natural gas			3,658				19,945				23,603				23,982
Loss on derivative financial instruments			(11,079	)			—				(11,079	)			—
Total			50,192				274,772				324,964				363,985
Average costs (per Boe):
LOE		$	25.16			$	22.44			$	22.93			$	19.99
Taxes, other than on earnings			1.21				1.36				1.33				1.33
General and administrative (“G&A”) expenses			3.71				15.96				13.76				3.44
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil										$	(22,032	)
Changes in production volumes of oil											(5,531	)
Total decrease in oil sales										$	(27,563	)
Changes in prices of natural gas										$	6,046
Changes in production volumes of natural gas											(6,425	)
Total decrease in natural gas sales										$	(379	)

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Overview

Our operating results for the six months ended June 30, 2014, compared to the six months ended June 30, 2013, reflect a 2% decrease in oil production and a 23% decrease in natural gas production, resulting in a 7% decrease in our overall production volumes. Our product mix for the six months June 30, 2014 was 80% oil (including natural gas liquids) compared to 75% for the six months ended June 30, 2013.

Revenue

		Period from June 4, 2014 through June 30, 2014 (Restated)				Period from January 1, 2014 through June 3, 2014				Non-GAAP Combined Results for the Six Months Ended June 30, 2014 (Restated)				Six Months Ended June 30, 2013				$ Change				% Change
		(in thousands)				(in thousands)
Oil and natural gas revenues		$	61,271			$	274,772			$	336,043			$	363,985			$	(27,942	)			-8	%
Gain (loss) on derivative financial instruments			(11,079	)			—				(11,079	)			—				(11,079	)

For the six months ended June 30, 2014, our oil and natural gas revenues decreased 8% as compared to the six months ended June 30, 2013, due primarily to a decrease of 6% in average selling prices for our oil. The decrease in our oil and natural gas revenues also reflects the 2% decrease in oil production and 23% decrease in natural gas production, partially offset by a 27% increase in average selling prices for natural gas in the six months ended June 30, 2014, as compared to the six months ended June 30, 2013. In addition, revenues for the period from June 4, 2014 through June 30, 2014 and the non-GAAP combined revenues for the six months ended June 30, 2014 include a reduction of $11.1 million due to loss on derivative financial instruments.

Our overall production volumes decreased by 7% for the six months ended June 30, 2014 when compared to the six months ended June 30, 2013. During the first two months of 2014, we experienced significant weather-related downtime, which negatively impacted the average oil production for the period. Our GoM shelf production decreased 6% in the six months ended June 30, 2014, as compared to the six months ended June 30, 2013, due primarily to a decrease in production in our West Delta field, which was partially offset by an increase in production in our Ship Shoal 208 area and production from the acquired interests in the Eugene Island and South Pass 49 fields.

Operating Expenses

Our operating expenses primarily consisted of the following:

		Period from June 4, 2014 through June 30, 2014				Period from January 1, 2014 through June 3, 2014				Non-GAAP Combined Results for the Six Months Ended June 30, 2014				Six Months Ended June 30, 2013				$ Change				% Change
		(in thousands)				(in thousands)
LOE		$	17,746			$	72,302			$	90,048			$	84,372			$	5,676				7	%
Exploration expenditures and dry hole costs(1)			—				26,239				NM				8,463
Impairments(1)			—				61				NM				2,171
DD&A, including accretion expense(1)			24,797				96,898				NM				112,056
G&A expenses			2,617				51,434				54,051				14,501				39,550				273	%
Taxes, other than on earnings			850				4,384				5,234				5,599				(365	)			-7	%
Other			—				44				44				6,543				(6,499	)			-99	%

NM — Not meaningful.

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LOE increased for the six months ended June 30, 2014, compared to the six months ended June 30, 2013, primarily due to employee severance costs of $3.4 million related to the Merger. LOE for the six months ended June 30, 2014 also included approximately $3.2 million of non-routine workover expenses as compared to $6.0 million for the six months ended June 30, 2013.

Exploration expenditures and dry hole costs for the period from January 1, 2014 through June 3, 2014 include dry hole costs totaling approximately $14.8 million, primarily associated with an exploratory drilling operation which reached its target depth in June 2014 and was determined to be unsuccessful. In addition, exploration expenditures and dry hole costs for the period from January 1, 2014 through June 3, 2014 include seismic expense of $2.4 million and other exploratory costs totaling approximately $9.0 million, primarily associated with our geological and geophysical staff, including non-cash share-based compensation due to accelerated vesting of outstanding stock options and restricted shares at the time of the Merger totaling approximately $3.9 million. During the six months ended June 30, 2013, we recorded approximately $3.7 million of dry hole costs associated with an exploratory drilling operation during the quarter ended June 30, 2013. In addition, exploration expenditures and dry hole costs for six months ended June 30, 2013 include seismic expense of $1.2 million and other exploratory costs totaling approximately $3.6 million, primarily associated with our geological and geophysical staff. Prior to adopting the full cost method of accounting, our exploratory expenditures and dry hole costs could vary significantly depending on the amount of capital expenditures dedicated to exploration activities and the level of success we achieved in exploratory drilling activities.

G&A expenses increased for the six months ended June 30, 2014, as compared to the six months ended June 30, 2013, primarily due to expenses related to the Merger, including third party legal and financial advisory costs totaling approximately $11.2 million, non-cash share-based compensation due to accelerated vesting of outstanding stock options and restricted shares at the time of the Merger totaling approximately $11.8 million, employee severance costs of approximately $8.7 million and the impact of employee bonuses approved in connection with the Merger of approximately $5.1 million.

During the six months ended June 30, 2013, we recorded loss on abandonment activities totaling $5.4 million and amortization expense related to our weather derivative of $1.3 million in other operating expenses.

Other Income and Expense

Interest expense for the period from June 4, 2014 to June 30, 2014 includes interest on our 8.25% Senior Notes and borrowings on the revolving credit sub-facility as described in Liquidity and Capital Resources. For the period January 1, 2014 through June 3, 2014 and the six months ended June 30, 2013, our interest expense included interest on our 8.25% Senior Notes and interest on borrowings on our prior senior credit facility.

Other income (expense) for the period January 1, 2014 through June 3, 2014 includes a net loss on derivative instruments of $19.4 million consisting of a loss of $26.4 million on derivative instruments settled during the period primarily from the impact of higher oil prices on our oil fixed-price swaps and a gain of $7.0 million due to the change in fair value of derivative instruments which were to be settled in the future. Other income (expense) in the six months ended June 30, 2013 includes a net gain on derivative instruments of $23.0 million consisting of a gain of $27.3 million due to the change in fair value of derivative instruments which were to be settled in the future and a loss of $4.3 million on derivative instruments settled during the period primarily from the impact of higher oil prices on our oil fixed-price swaps.

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Results of Operations — Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

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

		Year Ended December 31,
		2013				2012
Net production (per day):
Oil (Bbls)			16,938				10,398
Natural gas (Mcf)			32,863				17,852
Total (Boe)			22,415				13,373
Average sales prices(1):
Oil (per Bbl)		$	104.01			$	106.08
Natural gas (per Mcf)			3.81				2.89
Total (per Boe)			84.18				86.33
Oil and natural gas revenues (in thousands):
Oil		$	643,033			$	403,663
Natural gas			45,710				18,866
Total			688,743				422,529
Impact of derivatives instruments settled during the period:
Oil (per Bbl)		$	(1.78	)		$	(0.88	)
Natural gas (per Mcf)			(0.04	)			(0.07	)
Average costs (per Boe):
LOE		$	20.27			$	19.38
Depreciation, depletion and amortization (“DD&A”)			24.49				23.21
Accretion of liability for asset retirement obligations			3.46				3.18
Taxes, other than on earnings			1.40				2.66
General and administrative (“G&A”) expenses			3.44				4.74
Increase (decrease) in oil and natural gas revenues due to:
Changes in prices of oil		$	(7,879	)
Changes in production volumes of oil			247,249
Total decrease in oil sales		$	239,370
Changes in prices of natural gas		$	6,017
Changes in production volumes of natural gas			20,827
Total increase in natural gas sales		$	26,844

Overview

Our operating results for the year ended December 31, 2013, compared to the year ended December 31, 2012, reflect a 63% increase in oil production and an 84% increase in natural gas production. Our product mix for the year ended December 31, 2013 was 76% oil (including natural gas liquids) compared to 78% for the year ended December 31, 2012, resulting in a 68% increase in our overall production volumes for the year ended December 31, 2013 when compared to the year ended December 31, 2012.

Revenue and Net Income

		Years Ended December 31,
		2013				2012				$ Change				% Change
		(in thousands)
Oil and natural gas revenues		$	688,743			$	422,529			$	266,214				63	%
Net income			85,274				58,810				26,464				45	%

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For the year ended December 31, 2013, our oil and natural gas revenues increased 63% as compared to the year ended December 31, 2012, due primarily to the 63% increase in oil production, partially offset by slightly lower average selling prices for our oil. The increase in our oil and natural gas revenues also reflects the 84% increase in natural gas production and a 32% increase in average selling prices for natural gas in the year ended December 31, 2013, as compared to the year ended December 31, 2012.

Our GoM shelf production, excluding production from properties acquired in the acquisition of the 100% membership interests of Hilcorp Energy GOM, LLC in October 2012 (the “Hilcorp Properties”), increased 29% in the year ended December 31, 2013, as compared to the year ended December 31, 2012, due primarily to production increases in our West Delta, South Pass 49 and Main Pass fields partially offset by production declines in our South Timbalier area. Production from the Hilcorp Properties increased our production rate by approximately 5,902 Boe per day in the year ended December 31, 2013, compared to results for the year ended December 31, 2012, which include production from the Hilcorp Properties only for the period from November 1 to December 31, 2012, reflecting a 1,488 Boe per day impact on the production rate in the prior period.

In addition to the items addressed above, our net income for the year ended December 31, 2013 included a gain on sale of assets of $28.7 million, primarily from the sale of the interests in the Bay Marchand field; a loss on abandonment activities of $27.2 million; interest expense of $52.4 million and a net loss on derivative instruments of $32.4 million. Our net income for the year ended December 31, 2012 reflected a loss on abandonment activities of $2.4 million; interest expense of $28.6 million and a net loss on derivative instruments of $13.3 million.

For the years ended December 31, 2013 and 2012, our effective income tax rate was 36.8% and 33.7%, respectively, and the income tax expense that we recorded was all deferred. For the year ended December 31, 2012 the income tax expense that we recorded was reduced due to applying the change in our estimated effective income tax rate to our net deferred tax liabilities. The change in our estimated effective income tax rate from 37.3% in 2011 to 36.4% in 2012 was primarily related to estimated state income taxes.

Operating Expenses

Our operating expenses primarily consisted of the following:

		Years Ended December 31,
		2013				2012				$ Change				% Change
		(in thousands)
LOE		$	165,841			$	94,850			$	70,991				75	%
Exploration expenditures and dry hole costs			26,555				18,799				7,756				41	%
Impairments			2,937				8,883				(5,946	)			-67	%
DD&A, including accretion expense			228,658				129,146				99,512				77	%
G&A expenses			28,137				23,208				4,929				21	%
Taxes, other than on earnings			11,490				13,007				(1,517	)			-12	%
Other			34,942				4,678				30,264				647	%

LOE increased for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to the acquisition of the Hilcorp Properties. LOE for the year ended December 31, 2013 also included approximately $8.2 million of non-routine workover expenses.

Exploration expenditures and dry hole costs increased for the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily reflecting costs associated with the increased size of our geological and geophysical staff. We also had increases in seismic expense and dry hole costs. For the year ended December 31, 2013, seismic expense, was $12.3 million compared to $10.6 million for the year ended December 31, 2012. Our seismic expense for the year ended December 31, 2013 related primarily to the 3-D seismic agreements negotiated during the year. Our seismic expense for the year ended December 31, 2012 related to area-wide 2-D and 3-D seismic purchases. For the year ended December 31, 2013, we recorded approximately $5.5 million of dry hole costs, primarily associated with an exploratory drilling operation during the year which was unsuccessful. For the year ended December 31, 2012, we recorded approximately $4.2 million of dry hole costs, primarily associated with two exploratory wells which reached

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their target depths in January 2012 and were determined to be unsuccessful and an unsuccessful exploratory portion of a well that was successfully completed in a development zone.

Impairments for the year ended December 31, 2013 were primarily related to reservoir performance at a gas well in one of our smaller producing fields. This field was determined to have future net cash flows less than its carrying value resulting in the write down of this property to its estimated fair value during the year ended December 31, 2013. Impairments for the year ended December 31, 2012 were primarily due to the decline in our estimate of future natural gas prices, which affected three of our natural gas producing fields and reservoir performance at two of those fields. These fields were determined to have future net cash flows less than their carrying values resulting in the write down of these properties to their estimated fair values. We also recorded impairments for undeveloped leases that were expiring in 2013 for which we had no development plans.

DD&A increased for the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily due to the increase in production associated with the acquisition of the Hilcorp Properties.

G&A expenses increased for the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily as a result of higher professional fees related to the expansion of our asset base following the acquisition of the Hilcorp Properties and an increase in non-cash share-based compensation. G&A per Boe for the year ended December 31, 2013, as compared to the year ended December 31, 2012, declined significantly because of the increase in production primarily from the Hilcorp Properties.

Taxes, other than on earnings, were lower in the year ended December 31, 2013, as compared to the year ended December 31, 2012. The decrease was primarily related to severance taxes and a decrease in production from state leases (which is subject to a severance tax regime).

Other operating expenses increased for the year ended December 31, 2013, as compared to the year ended December 31, 2012, primarily as a result of an increase in loss on abandonment activities and amortization of the premium paid for our weather derivative. During the year ended December 31, 2013, we recorded loss on abandonment activities totaling $27.2 million and amortization expense related to our weather derivative of $8.0 million. During the year ended December 31, 2012, we recorded loss on abandonment activities totaling $2.4 million and amortization expense related to our weather derivative of $2.4 million. For the year ended December 31, 2013, our loss on abandonment activities primarily reflected an increase of $20.8 million in our asset retirement obligation liability related to our non-operated deepwater properties.

Other Income and Expense

Interest expense increased for the year ended December 31, 2013, as compared to the year ended December 31, 2012. The increase in our interest expense was due to the full year of interest on our 8.25% Senior Notes issued in connection with the acquisition of the Hilcorp Properties and borrowings on our prior senior credit facility for the year ended December 31, 2013. For the year ended December 31, 2012, our interest expense included interest on our 8.25% Senior Notes and interest on borrowings on the prior senior credit facility beginning in late October 2012 in connection with the acquisition of the Hilcorp Properties.

Other income (expense) in the year ended December 31, 2013 included a net loss on derivative instruments of $32.4 million consisting of a loss of $20.9 million due to the change in fair value of derivative instruments to be settled in the future and a loss of $11.5 million on derivative instruments settled during the period primarily from the impact of higher oil prices on our oil fixed-price swaps. Other income (expense) in the year ended December 31, 2012 includes a net loss on derivative instruments of $13.3 million consisting of a loss of $9.5 million due to the change in fair market value of derivative instruments and a loss of $3.8 million on derivative instruments settled during the period primarily from the impact of higher oil prices during 2012 on our oil fixed-price swaps.

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Liquidity and Capital Resources

Overview

As of June 30, 2015, we had $150 million in borrowings outstanding under the First Lien Credit Agreement, as amended, to which we are a party with EGC. Currently, we fund our operations primarily through cash flows from operating activities and advances from EGC. Future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. Oil prices declined severely during the second quarter of our fiscal year 2015, with continued lower prices throughout the second half of fiscal year 2015. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our ability to maintain and grow reserves and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. For example, constraints in the credit markets may increase the rates we are charged for utilizing these markets. Based on our current production levels and prices for oil and natural gas, our liquidity and capital resource alternatives may not be sufficient to meet our funding requirements through June 30, 2016, without additional advances from EGC, further reductions in capital expenditures or sales of non-core assets by us or EGC. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we will have to take certain actions described in greater detail in “Risk Factors — We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.”

Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement for the near term; however, a protracted period of low commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods, including prior to June 30, 2016. Our parent and EGC intend to support us financially to enable us to meet our ongoing obligations and comply with our covenants. However, in the event that we are unable to comply with these covenants, a breach of the covenants under our revolving credit sub-facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under our revolving credit sub-facility. If the lenders under our credit facility were to accelerate the indebtedness under our revolving credit facility as a result of such defaults, such acceleration could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness, as well as all of EGC’s and our parent’s other outstanding indebtedness. As of June 30, 2015, EGC and our parent had outstanding indebtedness of $3,916 million, excluding all of 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 may not have sufficient liquidity to repay all of our outstanding indebtedness.

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

Our Indebtedness and Available Credit

Revolving Credit Sub-Facility.  During March 2015, the Tenth Amendment to the First Lien Credit Agreement dated as of March 3, 2015 (the “Tenth Amendment”) became effective. Pursuant to the terms of the Tenth Amendment, the lenders under the First Lien Credit Agreement reduced the borrowing base for EGC from $1,500 to $500 million, of which such amount $150 million is the borrowing base for EPL (the

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“Revolving Credit Sub-Facility”). The maturity date of the First Lien Credit Agreement is April 9, 2018, provided that certain conditions are met; however, the maturity of the revolving credit facility will accelerate if EGC’s 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. Additionally, we entered into a $325 million secured second lien promissory note between us, as the maker, and EGC, as the payee (the “Promissory Note”) on March 12, 2015. Proceeds from the Promissory Note were used to repay a like amount of the outstanding borrowings under the Revolving Credit Sub-Facility. As of June 30, 2015, we have fully utilized amounts available under our Revolving Credit Sub-Facility. For more information on our Revolving Credit Sub-Facility and the Promissory Note, see Note 8, “Indebtedness” in Part II, Item 8 of this Form 10-K.

Additionally, as of July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver to the First Lien Credit Agreement (the “Eleventh Amendment”), which waives certain provisions of the First Lien Credit Agreement to permit certain transactions entered into by other subsidiaries of Energy XXI. Further, the Eleventh Amendment temporarily increased the letter of credit commitment amount within the facility from $300 million to a maximum amount of $305 million through August 31, 2015, after which it reduced back to $300 million.

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

As of June 30, 2015, we were in compliance with all covenants under the First Lien Credit Agreement, other than with respect to the sale of interests in the East Bay field. Since required lender consent to the specific terms of the transaction had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required EGC to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC. Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement for the near term; however, a protracted period of low commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods, including prior to June 30, 2016. Our parent and EGC intend to support us financially to enable us to meet our ongoing obligations and comply with our covenants.

As a result of EGC’s reduction in borrowing base availability to $500 million and the resulting increased asset coverage for the Revolving Credit Facility, we do not currently anticipate any further borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, EGC’s borrowing base and our borrowing base under the Revolving Credit Sub-Facility may be further reduced, which would impact the working capital available to fund our capital spending program. In addition, we would be required to repay any outstanding indebtedness in excess of any reduced borrowing base.

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8.25% Senior Notes.  The 8.25% Senior Notes consist of $510.0 million in aggregate principal amount issued under an indenture da