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

SECURITIESForm AND EXCHANGE COMMISSION 10-K

Washington, D.C. 20549


(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

Form 10-KCommission file number: 001-16179

(MarkEPL One)Oil & Gas, Inc.

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)Exact OFname THEof SECURITIESregistrant EXCHANGEas ACTspecified OFin 1934its charter)

For the fiscal year ended December 31, 2013


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)

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d713) OF THE SECURITIES EXCHANGE ACT OF 1934 351-3000

~~For~~Registrant’s ~~the~~telephone ~~transition~~number, ~~period~~including ~~from to~~ area code

CommissionSecurities fileregistered number:pursuant 001-16179to Section 12(b) of the Act:

EPL Oil & Gas, Inc. None

(ExactSecurities nameregistered ofpursuant registrantto asSection specified12(g) inof itsthe charter) Act:

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

None

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

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(~~713~~d) ~~228-0711~~ of the Act. Yes x No o

~~Registrant’s~~Indicate ~~telephone~~by ~~number~~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), ~~including~~and ~~area~~(2) ~~code~~ has been subject to such filing requirements for the past 90 days. Yes o No x

~~Securities~~Indicate ~~registered~~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 ~~Section 12~~Rule 405 of Regulation S-T (b)§232.405 of this chapter) during the ~~Act:~~preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Title of each class	Name of exchange on which registered
Common Stock, Par Value $0.001 Per Share	New York Stock Exchange

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

~~Securities~~Indicate ~~registered~~by ~~pursuant~~check tomark ~~Section 12(g)~~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: .

~~None~~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 ifwhether the registrant is a ~~well-known~~shell ~~seasoned~~company ~~issuer,~~ (as defined in Rule ~~405~~ 12b-2 of the ~~Securities~~ Act). Yes x o No ¨ x

Indicate by check mark ifwhether the registrant ishas ~~not~~filed ~~required~~all todocuments ~~file~~and reports ~~pursuant~~required to ~~Section~~ be filed by Sections 12, 13 or ~~Section~~ 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ~~¨ Nox~~ x No o

~~Indicate~~There byis ~~check~~no ~~mark~~market ~~whether~~for the ~~registrant~~common ~~(1) has~~stock ~~filed all reports required to be filed by Section 13 or 15(d)~~ of ~~the~~EPL ~~Securities~~Oil ~~Exchange~~& ~~Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports)~~Gas, ~~and (2) has been subject to such filing requirements for the past 90 days~~Inc. ~~Yesx No ¨~~

IndicateOMISSION byOF checkCERTAIN 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 ¨ INFORMATION:

~~Indicate~~EPL byOil ~~check~~& ~~mark~~Gas, ifInc. ~~disclosure~~meets ofthe ~~delinquent~~conditions ~~filers~~set ~~pursuant~~forth toin ~~Item 405~~General ofInstruction ~~Regulation S-K~~ I(~~§ 229.405 of this chapter~~1)(a) ~~is not contained herein,~~ and ~~will~~(b) ~~not be contained, to the best~~ of ~~registrant’s~~Form ~~knowledge,~~10-K inand ~~definitive~~is ~~proxy~~therefore orfiling ~~information~~this ~~statements~~form ~~incorporated~~with bythe ~~reference~~reduced indisclosure ~~Part III~~format ofallowed ~~this~~under ~~Form 10-K~~that orGeneral ~~any amendment to this Form 10-K~~Instruction. x

IndicateDOCUMENTS byINCORPORATED checkBY 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. REFERENCE:

~~Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ¨ (Do not check if a smaller reporting company) Smaller reporting company ¨~~None

~~Indicate~~TABLE byOF ~~check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x~~ CONTENTS

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

The aggregate market value of the common stock held by non-affiliates of the registrant at June 30, 2013 (the registrant’s most recently completed second fiscal quarter) based on the closing stock price as quoted on the New York Stock Exchange on that date was $1,066,066,044. As of February 21, 2014, there were 39,206,958 shares of the registrant’s common stock, par value $0.001 per share, outstanding.


	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

~~DOCUMENTS INCORPORATED BY REFERENCE:~~ i

~~Portions~~TABLE ofOF ~~the Proxy Statement for the Annual Meeting of Stockholders of EPL Oil & Gas, Inc. expected to be held on May 1, 2014 are incorporated by reference into Part III of this Annual Report on Form 10-K.~~ CONTENTS

TABLECAUTIONARY OFSTATEMENT CONTENTSREGARDING FORWARD-LOOKING STATEMENTS

		Page
	PART I
Item 1.	Business	2
	Cautionary Statement Concerning Forward Looking Statements	17
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	35
Item 2.	Properties	35
Item 3.	Legal Proceedings	35
Item 4.	Mine Safety Disclosures	35
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	54
Item 8.	Financial Statements and Supplementary Data	56
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	91
Item 9A.	Controls and Procedures	91
Item 9B.	Other Information	92
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	92
Item 11.	Executive Compensation	92
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	92
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accountant Fees and Services	92
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	93

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:

1 • our business strategy;

~~Statements~~• wefurther ~~make in this Annual Report on Form 10-K (“Annual Report”) which express a belief, expectation~~ or ~~intention,~~sustained asdeclines ~~well~~in ~~as those that are not historical fact, may constitute forward-looking statements within~~ the ~~meaning~~prices ~~of the Private Securities Litigation Reform Act of 1995. Our forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which~~ we ~~refer~~receive ~~under~~for ~~the~~our ~~headings~~oil ~~“Cautionary Statement Concerning Forward-Looking Statements”~~ and ~~“Risk~~gas ~~Factors” in Items 1 and 1A of Part 1 of this Annual Report.~~ production;

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

~~Item 1.Business~~• our future levels of indebtedness, liquidity and compliance with debt covenants;

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

~~EPL~~• ~~Oil~~economic &slowdowns ~~Gas,~~that ~~Inc.~~can ~~(referred~~adversely toaffect ~~herein~~consumption asof ~~“we,” “our,” “us” or the “Company”) was incorporated as a Delaware corporation in January 1998 and operates as an independent~~ oil and ~~natural~~ gas exploration and production company based in Houston, Texas and New Orleans, Louisiana. Effective September 1, 2012, we changed our legal corporate name from “Energy Partners, Ltd.” to “EPL Oil & Gas, Inc.” through a short-form merger pursuant to Section 253 of the General Corporation Law of the State of Delaware. Our current operations are concentrated in the U.S. Gulf of Mexico 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~~businesses ~~exploitation, development~~ and exploration opportunities in both productive horizons and deeper geologic formations. Our management professionals and technical staff have considerable geological, geophysical and operational experience that is specific to the Gulf of Mexico and Gulf Coast region, and we have acquired and developed geophysical and geological data relating to these areas. We intend to pursue capital-efficient development and exploration activities in our core area, as well as identify acquisition opportunities that leverage our technical and operational strengths. As of December 31, 2013, we had estimated proved reserves of 80.4 Mmboe, of which 64% were oil and 71% were proved developed. Of these proved developed reserves, 69% were oil reserves. consumers;

We• ~~produce~~uncertainties ~~both~~in estimating oil and ~~natural~~ gas. ~~Throughout this Annual Report, when we refer to “total production,” “total~~ reserves,” ~~“percentage~~and ofnet ~~production,”~~present ~~“percentage~~values of ~~reserves,”~~those ~~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 Annual Report.

~~For~~• ~~definitions~~the ofneed ~~oil~~to ~~and~~take ~~natural~~ceiling ~~gas~~test ~~terms~~impairments ~~used~~due ~~frequently in this Annual Report, please refer~~ to ~~the~~lower ~~“Glossary~~commodity ~~of Oil and Natural Gas Terms” following the index of Exhibits in Item 15 of Part IV of this Annual Report.~~ prices;

~~The~~• ~~following~~hedging ~~summarizes~~activities ~~our~~exposing ~~acquisitions~~us ~~(purchase~~to ~~prices~~pricing ~~are~~and ~~before~~counterparty ~~economic effective date adjustments):~~ risks;

~~Acquisitions~~ • uncertainties in estimating our oil and gas reserves;

·• Onreplacing ~~January~~our ~~15, 2014, we acquired 100% working interest of certain shallow-water central Gulf of Mexico shelf~~ oil and ~~natural~~ gas ~~assets in the Eugene Island 258/259 field for $70.4 million (the “Nexen Acquisition”)~~reserves;

·• Ongeographic ~~September~~concentration ~~26, 2013, we acquired an asset package consisting~~ of ~~certain~~our ~~Gulf of Mexico shelf oil and natural gas interests in the West Delta 29 field (the “WD29 Interests”) for $21.8 million~~assets;

·• Onuncertainties ~~October~~in ~~31,~~exploring ~~2012,~~for weand ~~acquired~~producing ~~100% of the membership interests of Hilcorp Energy GOM, LLC (“Hilcorp Acquisition”), which owned certain shallow water Gulf of Mexico shelf~~ oil and ~~natural~~ gas, ~~interests~~including ~~(the~~exploitation, ~~“Hilcorp Properties”) for $550 million. The Hilcorp Properties included three core producing complexes in the Ship Shoal 208~~development, ~~South~~drilling ~~Pass 78~~ and ~~South~~operating ~~Marsh Island 239 areas~~risks;

·• Onour ~~May~~ability ~~15,~~to ~~2012,~~make weacquisitions ~~acquired an asset package consisting of certain shallow-water Gulf of Mexico shelf oil~~ and ~~natural~~to ~~gas~~integrate ~~interests in our South Timbalier 41 field located in the Gulf of Mexico for $32.4 million (the “ST41 Interests”)~~acquisitions;

·• Onour ~~November~~ability ~~17,~~to ~~2011,~~establish weproduction ~~acquired~~on ~~interests~~our inacreage ~~the~~prior ~~Main~~to ~~Pass 296/311 complex along with other unit interests in~~ the ~~Main~~expiration ~~Pass~~of ~~complex~~related ~~and an interest in a Main Pass 295 primary term lease for $38.6 million (the “Main Pass Interests”)~~leaseholds; ~~and~~

·• Onavailability ~~February 14, 2011, we acquired from Anglo-Suisse Offshore Partners, LLC (“ASOP”) an asset package consisting~~ of ~~certain~~drilling ~~shallow-water Gulf of Mexico shelf oil~~ and ~~natural~~production ~~gas~~equipment, ~~interests~~facilities, ~~surrounding~~field ~~the~~service ~~Mississippi~~providers, ~~River delta and a related~~ gathering, ~~system~~processing ~~(the “ASOP Properties”) for $200.7 million. The ASOP Properties included two core producing complexes in the West Delta~~ and ~~Main Pass areas and an interest in the South Pass 49 field.~~transportation;

2 • disruption of operations and damages due to capsizing, collisions, hurricanes or tropical storms;

~~Dispositions~~ • environmental risks;

·• ~~On April 2~~availability, ~~2013,~~cost ~~we sold certain shallow water Gulf of Mexico shelf oil~~ and ~~natural~~adequacy ~~gas interests located within the non-operated Bay Marchand field for total consideration~~ of ~~$62.8~~insurance ~~million.~~coverage;

~~See~~• ~~“Management’s~~competition ~~Discussion~~in ~~and~~the ~~Analysis~~oil ~~of Financial Condition~~ and ~~Results~~gas ~~of Operations” for more information regarding these transactions.~~ industry;

~~Competitive~~• ~~Strengths~~our inability to retain and attract key personnel;

~~High~~• ~~Quality~~the ~~Asset~~effects Base with Significant Exploitation and Exploration Potential. We believe our asset base is characterized by lower-risk properties that have more predictable well control and production profiles. Our net proved reserves as of ~~December 31,~~government ~~2013~~regulation ~~were 71% proved developed, which provides significant production visibility. Moreover, we have an inventory of lower risk exploitation projects with 209 behind pipe opportunities~~ and 35permitting ~~identified proved undeveloped reserves locations. Our portfolio of fields offer significant development~~ and ~~exploration~~other ~~potential,~~legal ~~with multiple producing zones and unexplored deeper horizons.~~ requirements;

Oil-Weighted Reserves and Production. We believe we are more oil-focused in both our reserves and production as compared to many of our peers. Our net proved reserves at December 31, 2013 were approximately 64% oil, and our net average daily production for the year ended December 31, 2013 was 76% oil. Given the current commodity price environment and resulting disparity between oil and natural gas prices on a barrel of oil equivalent basis, we believe our high percentage of oil reserves compared to our overall reserve base provides us an economic advantage. Additionally, the production decline curve of oil is typically lower than a natural gas decline curve, resulting in longer term production from current reserves. 1

~~Operational~~TABLE ~~Control.~~OF We operate properties that contain approximately 89% of our proved reserves. As the operator of a property, we are afforded greater control of the optimization of production, the timing and amount of capital expenditures, and the operating parameters and costs of our projects. As such, we are able to align capital expenditures with cash flow because we are generally able to adjust drilling and development plans in response to changes in commodity prices. CONTENTS

~~Geographically~~• ~~Focused Properties in the Gulf of Mexico. We are focused on operating properties located in the Gulf of Mexico shelf, which gives us the opportunity to minimize logistical and administrative~~ costs ~~and~~associated ~~maximize~~with ~~the~~perfecting ~~productivity~~title offor ~~our~~mineral ~~field~~rights ~~personnel. Our concentration of long-lived, oil rich legacy fields provides attractive future consolidation opportunities as evidenced by the Hilcorp and Nexen acquisitions. Our experience~~ in ~~the~~some ~~Gulf~~ of ~~Mexico, and particularly offshore Louisiana, has led us to focus~~ our ~~efforts~~properties; ~~in that particular region, where we are familiar with the fields, drilling~~ and ~~production trends and where we have amassed an extensive library of geologic information.~~

In• ~~2012~~weaknesses ~~we acquired additional 2-D and 3-D seismic data sets~~ in our ~~current~~internal ~~offshore operating areas and onshore Louisiana where the geology is characterized by similar productive horizons and structural features~~controls. In addition to the extensive seismic library we have of our legacy properties, we have licensed high quality multi-client 3-D data sets for recently acquired fields. We now have approximately 21,119 square miles of 3-D seismic data in the Gulf of Mexico and onshore Louisiana. This seismic data assists us in identifying attractive development and exploration drilling opportunities that adhere to our capital-efficient development strategies. We continue to high-grade these data sets by employing state-of-the-art reprocessing techniques for the data covering our core fields and on a regional basis around those fields. These technological upgrades are creating better images of prospective horizons and aiding in the evaluation of drilling opportunities.

~~Additionally,~~For inadditional ~~September~~information ~~and~~regarding ~~October~~known ~~2013,~~material wefactors ~~negotiated~~that ~~agreements~~could ~~totaling~~cause ~~approximately~~our ~~$45~~actual ~~million~~results ~~with seismic companies~~ to ~~acquire~~differ ~~3-D~~from ~~seismic licenses over~~ our ~~core~~projected ~~areas. These~~results, ~~agreements~~please ~~include~~read a(1) ~~commitment~~Part toI, ~~acquire~~Item ~~area-wide~~1A. ~~data~~“Risk ~~licenses~~Factors” ~~for~~and ~~seismic~~elsewhere ~~acquisitions~~in ~~that~~this ~~will~~Form be10-K, ~~performed~~(2) byour ~~the~~reports ~~seismic company during 2014, 2015~~ and ~~2016~~registration ~~covering~~statements afiled ~~minimum~~from oftime ~~200~~to ~~blocks,~~time orwith ~~approximately~~the ~~one~~Securities ~~million~~and ~~acres,~~Exchange ~~within~~Commission ~~the~~and ~~shallow~~(3) ~~water~~other ~~Gulf~~public ofannouncements ~~Mexico~~we ~~covering~~make ~~our~~from ~~core~~time ~~asset~~to ~~base~~time.

~~Conservative~~Readers ~~Fiscal~~are ~~Policy.~~cautioned Wenot ~~budget~~to ~~our~~place ~~capital~~undue ~~spending~~reliance on ~~exploration~~forward-looking ~~and~~statements, ~~development~~which ~~with~~speak ~~the~~only ~~goal~~as of ~~remaining~~the ~~within~~date ~~cash~~hereof. ~~flow~~We ~~from~~undertake ~~operations. We~~no ~~have~~obligation ~~hedged~~to ~~approximately~~publicly ~~67%~~update ofor ~~our~~revise ~~forecasted~~any ~~oil~~forward-looking ~~production~~statements ~~for~~after ~~2014~~the ~~and~~date ~~have~~upon ~~begun~~which ~~hedging~~they ~~forecasted~~are ~~production~~made, ~~for~~whether ~~2015~~as a result of new information, future events or otherwise.

ExperiencedEXPLANATORY ManagementNOTE and— SignificantRESTATEMENT TechnicalOF Expertise.FINANCIAL We have an experienced and technically-adept management team, averaging more than 25 years of industry experience among our top nine executives. We have also built a strong technical staff of geologists and geophysicists, field operations managers and engineers to handle all aspects of our exploitation, exploration, production and decommissioning activities. During the current year, we brought on eight additional geoscientists, engineers and technicians. 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 3 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.

~~Business~~This ~~Strategy~~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.

~~Pursue~~We ~~Capital~~do ~~Efficient~~not ~~Development~~plan into ~~Core~~amend ~~Areas.~~previously ~~Our~~filed ~~current~~reports ~~producing asset base~~ in ~~the~~connection ~~Gulf of Mexico shelf includes a large inventory of lower-risk exploitation opportunities, as well as exploration prospects~~ with ~~multiple~~the ~~objectives and follow-up opportunities~~restatement. InThe ~~2013,~~consolidated wefinancial ~~completed 21~~statements ~~workovers~~that ~~and~~have 17been ~~drill~~previously ~~wells,~~filed ~~with~~or ~~a 79%~~otherwise ~~success~~reported ~~rate,~~for ~~spending~~these ~~approximately~~periods ~~$335.9~~are ~~million~~superseded onby ~~development~~the ~~and~~information ~~exploration~~in ~~activities~~this ~~and~~Form ~~a total of $12~~10-K.3 ~~million~~Other onthan ~~seismic~~the ~~purchases. We~~historical ~~also~~information ~~spent~~reported ~~approximately~~for ~~$2 million~~the onPredecessor ~~undeveloped~~Company ~~leases~~for inperiods ~~2013. Our~~prior ~~fiscal~~to ~~year~~our ~~2014~~merger ~~capital~~with ~~budget~~Energy isXXI ~~$360 million~~Ltd, ~~which~~all isfinancial ~~allocated to development activities~~ and ~~exploration~~accounting ~~projects~~information ~~within~~contained ~~core field areas. Additionally, we plan to spend approximately $50 million~~ in ~~2014~~this onForm ~~plugging,~~10-K ~~abandonment~~is ~~and~~presented ~~other decommissioning activities. We will continue to focus~~ on ~~lower-risk development projects, as well as~~ a ~~small~~restated ~~number of high quality, high potential exploration prospects~~basis. We believe the properties we acquired in recent years enhance our exploitation strategy to increase production from legacy fields and provide us with substantial incremental exploration opportunities within those fields.

Build upon Regional Geologic Expertise. We are dedicating significant resources to add to our knowledge of the geology underlying our core areas. As previously described, in September and October 2013, we negotiated agreements totaling approximately $45 million with seismic companies to acquire 3-D seismic licenses over our core areas through 2017, of which we expect to spend approximately $13 million in 2014. We also have recently acquired additional 2-D and 3-D seismic data sets in our current offshore operating areas and onshore Louisiana, where the geology is characterized by similar productive horizons and structural features. Our geological and geophysical teams are analyzing well data, paleontological data and seismic data to identify exploration targets at intermediate and deep depths as well as associated acquisition opportunities.

~~Target~~TABLE ~~Acquisition~~OF Opportunities to Grow Reserves and Leverage Operational Strengths. We continue to review and monitor opportunities to acquire producing properties, leasehold acreage and drilling prospects in and around our core areas of operation so that we can act quickly as acquisition opportunities become available. Our acquisition strategy is focused on operated Gulf of Mexico shelf and Gulf Coast assets that are characterized by production-weighted reserves, seismic coverage and operated positions that would allow us to maintain a conservative capital structure. We intend to use acquisitions of this type as a key method to grow reserves and production because we believe this strategy increases production and cash flow visibility while reducing dry hole and exploration risk. We believe our expertise in the Gulf of Mexico and Gulf Coast region allows us to effectively evaluate acquisitions and to operate the properties we eventually acquire. CONTENTS

MaintainPART Financial Discipline. We strive to maintain a conservative financial position, sufficient liquidity and a strong balance sheet. We establish our capital spending plans with the goal of funding those costs with cash flows from operations. We currently have access to our senior credit facility (the “Senior Credit Facility”) which we entered into on February 14, 2011. On October 31, 2012, the facility was amended and restated in connection with the Hilcorp Acquisition to increase the aggregate commitment under the Senior Credit Facility from $250 million to a maximum of $750 million and to extend the maturity date to October 31, 2016. In January 2014, our lenders approved a $50 million increase in our borrowing base under our Senior Credit Facility, increasing our borrowing base to $475 million. As of February 21, 2014, we had $265 million in availability under our Senior Credit Facility. In order to maintain financial flexibility, we plan to fund our 2014 fiscal year exploration and development capital budget with cash flow from operations and borrowings under our Senior Credit Facility, as needed. Additionally, because we operate many of our properties, we are able to manage the timing of a substantial portion of our capital investments. We may fund future acquisitions with a combination of cash on hand, borrowings under our Senior Credit Facility and issuances of debt and equity securities under our universal shelf registration statement that became effective under the Securities Act of 1933 in July 2011. I

~~Capitalize~~Item ~~on Competency in Plugging and Abandonment~~1. We have established and are executing on a proactive, multi-year plan to plug, abandon and decommission depleted wells and associated infrastructure. Our chairman, president and chief executive officer has significant experience in conducting these types of operations and has supplemented our staff to accomplish this objective. In our East Bay field where our abandonment and decommissioning obligations are concentrated, we have completed plugging and abandonment operations on more than 48% of the inactive wellbores. We expect to reduce our lease operating expense over time by removing idle infrastructure and its associated maintenance costs. Business

Where You Can Find More Information Overview

WeEPL ~~maintain~~Oil a& ~~website~~Gas, ~~at www~~Inc.~~eplweb.com~~ ~~that~~(referred ~~contains~~to ~~information~~herein ~~about~~as us“we,” ~~which information is available free of charge, including links to~~ “our ~~Annual Reports on Form 10-K~~,” ~~Quarterly Reports on Form 10-Q~~“us,” ~~Current~~“EPL” ~~Reports~~or onthe ~~Form 8-K~~“Company”) ~~and~~was ~~all~~incorporated ~~related amendments~~ as ~~soon~~a asDelaware ~~reasonably~~corporation ~~practicable~~in ~~after~~January ~~electronically~~1998 ~~filing~~and ~~such~~is ~~reports~~a ~~with,~~wholly-owned orsubsidiary ~~furnishing~~of ~~them~~Energy toXXI ~~the~~Gulf ~~Securities~~Coast, ~~and~~Inc. ~~Exchange Commission~~ (~~the~~ “~~SEC~~EGC”)~~. In addition~~, ~~our~~a ~~website~~Delaware ~~contains~~corporation ~~our Corporate Governance Guidelines~~ and ~~the~~indirect ~~charters~~wholly-owned ~~for~~subsidiary ~~our Audit, Compensation, Nominating and Governance and Environmental, Health and Safety Committees. Copies~~ of ~~this~~Energy ~~information~~XXI ~~are also available by writing to our Corporate Secretary at 201 St. Charles Avenue~~Ltd, ~~Suite 3400,~~an ~~New~~exempted ~~Orleans,~~company ~~Louisiana~~under ~~70170. Our website and~~ the ~~information~~laws ~~contained~~of inBermuda it and ~~connected~~our toultimate itparent ~~shall~~company ~~not~~(“Energy beXXI” ~~deemed incorporated by reference into this Annual Report~~ or ~~any other filing that we make with the SEC~~“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 4 $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.”

WeOur ~~file~~current ~~Annual~~operations ~~Reports~~are onconcentrated ~~Form~~in ~~10-K,~~the ~~Quarterly~~U.S. ~~Reports~~Gulf onof ~~Form~~Mexico ~~10-Q,~~shelf ~~Current~~(the ~~Reports~~“GoM onshelf”) ~~Form~~focusing ~~8-K,~~on ~~proxy~~state ~~statements~~ and ~~other~~federal ~~documents~~waters ~~with~~offshore ~~the~~Louisiana, ~~SEC~~which ~~under~~we ~~the~~consider ~~Securities~~our ~~Exchange~~core ~~Act~~area. ofWe ~~1934~~have ~~(as~~focused ~~amended,~~on ~~the~~acquiring ~~“Exchange~~and ~~Act”).~~developing ~~The~~assets ~~public~~in ~~may~~this ~~read~~region, ~~and~~because ~~copy~~the ~~any~~region ~~materials~~is ~~that~~characterized weby ~~file~~established ~~with~~exploitation, ~~the~~development ~~SEC~~and atexploration ~~the~~opportunities ~~SEC’s~~in ~~Public~~both ~~Reference~~productive ~~Room~~horizons atand ~~100~~deeper Fgeologic ~~Street, NE, Washington, DC 20549~~formations. ~~The~~As ~~public~~part ~~may~~of ~~obtain~~Energy ~~information~~XXI’s onoverall ~~the~~strategy ~~operation~~and ofcapital ~~the~~plan, ~~Public~~we ~~Reference~~are ~~Room~~focused byon ~~calling~~developing ~~the~~high ~~SEC~~quality ~~at 1~~oil-~~800-SEC-0330.~~producing ~~Also,~~assets ~~the~~with ~~SEC~~low ~~maintains~~production andecline ~~internet~~rates. ~~website~~As ~~that~~of ~~contains~~June ~~reports~~30, ~~proxy and information statements~~2015, ~~and~~we ~~other~~had ~~information~~estimated ~~regarding~~proved reserves ~~issuers,~~of ~~including~~57.2 usMmboe, ~~that~~of ~~file~~which ~~electronically~~67% ~~with~~were ~~the~~oil ~~SEC.~~and ~~The~~76% ~~public~~were ~~can~~proved ~~obtain~~developed. ~~any~~Of ~~document~~these weproved ~~file~~developed ~~with~~reserves, ~~the~~70% ~~SEC~~were atoil ~~www~~reserves.~~sec.gov.~~

~~Properties~~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.

AsFor definitions of ~~December 31,~~oil ~~2013,~~and wenatural ~~had~~gas ~~working~~terms ~~interests~~used frequently in 32this ~~producing~~Form ~~fields~~10-K, ~~located~~please inrefer to the ~~Gulf~~“Glossary of ~~Mexico~~Oil ~~shelf region. The proved reserves~~ and ~~production~~Natural ~~from~~Gas ~~these~~Terms” ~~fields~~following ~~are primarily associated with~~ the ~~following~~index ~~core~~of ~~producing~~Exhibits ~~areas:~~in ~~Ship~~Item ~~Shoal~~15 ~~208,~~of ~~East~~Part ~~Bay,~~IV ~~West~~of ~~Delta,~~this ~~South~~Form ~~Timbalier, South Pass 78, Main Pass, South Marsh Island 239 and South Pass 49~~10-K.

DuringAvailable 2013, we concentrated on exploration and exploitation opportunities in the Ship Shoal 208, West Delta, South Pass 78 and Main Pass areas and evaluated certain well proposals in these areas using our recently reprocessed 3-D seismic data. Information

AsWe offile or furnish annual, quarterly and ~~for~~current reports and other documents with the ~~year~~Securities ~~ended~~and ~~December~~Exchange ~~31,~~Commission ~~2013~~(the “SEC”) under the Securities Exchange Act of 1934 (as amended, ~~our~~the ~~proved~~“Exchange ~~reserves~~Act”). The public may read and ~~production~~copy ~~from~~any ~~our~~materials ~~core~~that ~~producing~~we ~~areas~~file aswith ~~percentages~~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 ~~our~~the ~~total~~Public ~~proved~~Reference ~~reserves~~Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and ~~total~~information ~~production~~statements, ~~were~~and asother ~~follows:~~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.

	Proved Reserves			Production
Ship Shoal 208		24	%		10	%
East Bay		17			11
West Delta		15			32
South Timbalier		12			8
South Pass 78		10			7
Main Pass		6			8
South Marsh Island 239		4			4
South Pass 49		3			7

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.

Our Ship Shoal 208 complex is located 110 miles southwest of New Orleans. It contains 31 producing wells in average water depths of approximately 100 feet in three lease blocks. We operate the Ship Shoal 208 complex and own a working interest of 100% of the acreage position in this area. 3

~~Our~~TABLE ~~East~~OF Bay area includes the South Pass 24 and 27 fields and is located 89 miles southeast of New Orleans, near the mouth of the Mississippi River. It contains 197 producing wells located along the coastline and in water depths up to approximately 70 feet. We operate this field and own an average 96% working interest in our acreage position in this area. CONTENTS

Our West Delta complex, a legacy producing area, is located 62 miles south southeast of New Orleans. It contains 44 producing wells in water depths ranging from 29 to 87 feet and includes five lease blocks. We operate the West Delta complex and own an average 93% working interest in our acreage position in this area. Properties

~~Our~~As ~~South~~of ~~Timbalier~~June ~~area~~30, ~~includes~~2015, ~~the~~we ~~South~~had ~~Timbalier~~working 26interests ~~and~~in 4127 producing fields located ~~approximately~~in 60the toGoM 72shelf ~~miles~~region. ~~south~~The ofproved ~~New~~reserves ~~Orleans.~~and Itproduction ~~contains~~from 18these fields are primarily associated with the following core producing ~~wells~~areas: inShip ~~water~~Shoal ~~depths~~208, ofSouth ~~approximately~~Pass 7349, ~~feet~~West orDelta ~~less~~30 and South Pass 78. WeThese ~~operate~~properties ~~the~~represent ~~South~~approximately ~~Timbalier~~74% 26of ~~and~~our 41net ~~blocks,~~proved reserves and weare ~~own~~ranked abased ~~100% working~~on ~~interest~~highest inproved ~~this~~reserves ~~area~~as of June 30, 2015.

~~Our~~Ship ~~South~~Shoal ~~Pass~~208. We 78operate ~~complex~~and ishave a 100% working interest in the Ship Shoal 208 field, located 86110 miles ~~southeast~~southwest of New Orleans~~. It~~, ~~contains~~Louisiana 25in ~~producing~~approximately ~~wells~~100 infeet of water ~~depths~~on ~~ranging~~Outer ~~from~~Continental ~~approximately~~Shelf ~~140~~(“OCS”) toblocks ~~190~~Ship ~~feet~~Shoal in208, ~~four~~209 ~~lease~~and ~~blocks~~215. We ~~operate~~have 13 platforms and 31 active wells throughout the ~~South~~field. ~~Pass~~The 78field’s ~~complex~~net ~~and~~production ~~own~~for athe ~~working~~month ~~interest~~of June 2015 of 674.8 MBOED accounted for approximately 17% of our net production. Net proved reserves for the ~~acreage~~field ~~position~~were in70% ~~this~~oil ~~area~~at June 30, 2015.

~~Our~~South ~~Main~~Pass 49. Energy XXI operates and we have a 100% working interest in the South Pass ~~complex~~49 field, which is located 98near ~~miles~~the ~~southeast~~mouth of ~~New~~the ~~Orleans~~Mississippi River in approximately 400 feet of water. ItThere ~~contains~~are 3314 ~~producing~~active wells inlocated ~~average~~throughout ~~water~~the ~~depths~~field. ofThe ~~approximately~~field ~~250~~is ~~feet~~produced from one central production platform and ~~includes~~has produced in excess of 121 MMBOE. The field’s net production for the ~~Main~~month ~~Pass~~of ~~296~~June ~~and~~2015 ~~311~~of ~~fields~~4.6 WeMBOED ~~own~~accounted afor ~~non-operated~~approximately 5017% ~~working~~of ~~interest~~our innet ~~our~~production. ~~acreage~~Net ~~position~~proved inreserves ~~this~~for ~~area~~the field were 62% oil at June 30, 2015.

~~Our~~West ~~South~~Delta ~~Marsh~~30. We ~~Island~~operate ~~239~~and ~~complex~~have isan ~~located~~average ~~117~~93% ~~miles~~working ~~southwest~~interest ofin ~~New~~the ~~Orleans. It~~West ~~contains~~Delta ~~9 producing~~27, ~~wells~~28 inand ~~water~~29 ~~depths~~blocks, located 21 miles offshore of Grand Isle, Louisiana in approximately 2045 feet inof ~~four~~water ~~lease~~on ~~blocks~~the OCS. We ~~operate~~There are 46 active wells located throughout the ~~complex~~field. ~~and~~The ~~own~~field’s anet ~~working~~production ~~interest~~for the month of 92June 2015 of 5.2 MBOED accounted for approximately 19% inof our net production. Net proved reserves for the ~~acreage~~field ~~position~~were in86% ~~this~~oil ~~area~~at June 30, 2015.

~~Our~~South Pass 78. We operate and own a working interest of 67% in the South Pass 4978 ~~field~~complex, which is located ~~near~~86 ~~our~~miles ~~East~~southeast ~~Bay~~of ~~field~~New Orleans. It contains 6 31 producing wells in water depths ofranging from approximately ~~285~~140 to 190 feet in four lease blocks. We ~~own~~There aare ~~working~~four ~~interest~~major production platforms, three of 44which 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 ~~acreage~~field ~~position~~were in52% ~~this~~oil ~~area~~at June 30, 2015.

~~Our~~As ~~properties~~of ~~include~~June ~~other~~30, ~~producing~~2015, ~~fields~~we ~~offshore~~also ~~Louisiana~~owned ~~located~~interests in ~~water~~one ~~depths~~undeveloped ~~ranging~~lease ~~from~~in ~~approximately~~the 18deepwater toGulf ~~300~~of ~~feet~~Mexico ~~with~~and we have a non-operated interest in one developed lease. Our working interests ~~ranging~~in our leases in this area ranged from 715% to ~~100~~33%.

AsOn ofJune ~~December 31~~30, ~~2013~~2015, we ~~also~~sold ~~owned~~our ~~interests~~interest in 6the ~~undeveloped~~East ~~leases~~Bay infield ~~the~~for ~~deepwater~~cash ~~Gulf~~consideration of ~~Mexico~~approximately ~~and~~$21 wemillion, ~~have~~plus the assumption of asset retirement obligations totaling approximately $55.1 million. We retained a ~~non-operated~~5% overriding royalty interest in(applicable ~~one~~only ~~developed~~during ~~lease. Our~~calendar ~~working~~months ~~interests~~if inand ~~our~~when ~~leases~~the inWTI ~~this~~for ~~area~~such ~~ranged~~month ~~from~~averages ~~15%~~over $65) on these assets for a period not to 33exceed 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.

5 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.

SeeSummary “Management’s Discussion and Analysis of FinancialOil Condition and ResultsNatural ofGas Operations”Reserves for informationat regardingJune our oil and gas production30, average prices and average costs. 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 ~~Reserves~~

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 December 31, 2013, 2012 and 2011. Our estimates of proved reserves are based on a reserve report prepared as of December 31, 2013 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 15 “Supplementary Oil and Natural Gas Disclosures—(Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Annual Report provides important additional information about our proved oil and natural gas reserves. 4

WeTABLE ~~follow~~OF the oil and gas reserves estimation and disclosure requirements of 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 15 “Supplementary Oil and Natural Gas Disclosures—(Unaudited)” of the consolidated financial statements in Part II, Item 8 of this Annual Report for additional information regarding reporting related to oil and natural gas reserves under ASC 932. CONTENTS

	As of December 31,
	2013		2012		2011
	(dollars in thousands)
Total net proved reserves:
Oil (Mbbls)		51,517		47,442		27,301
Natural gas (Mmcf)		173,584		179,939		58,785
Total (Mboe)		80,448		77,432		37,099
Net proved developed reserves (1):
Oil (Mbbls)		39,439		37,908		24,791
Natural gas (Mmcf)		107,687		120,687		52,739
Total (Mboe)		57,387		58,022		33,581
Net proved undeveloped reserves:
Oil (Mbbls)		12,078		9,534		2,510
Natural gas (Mmcf)		65,897		59,252		6,046
Total (Mboe)		23,061		19,409		3,518
Estimated future net revenues before income taxes (2)	$	2,894,227	$	2,641,407	$	1,555,059
Present value of estimated future net revenues before income taxes (PV-10) (2)(3)(5)	$	2,109,324	$	1,979,274	$	1,100,701
Standardized measure of discounted future net cash flows (4)(5)	$	1,649,078	$	1,574,282	$	876,169

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.

~~(1)Net~~We ~~proved~~follow ~~developed~~the ~~non-producing~~oil and gas reserves asestimation and disclosure requirements of ~~December 31,~~the ~~2013~~ Financial Accounting Standards Board Accounting Standards Codification (13“ASC”) Topic 932,~~306~~ ~~Mbbls~~“Extractive Activities — Oil and ~~60,875~~Gas” ~~Mmcf~~(“ASC 932”), ~~were~~which 23requires,~~452~~ ~~Mboe~~among other things, orthat ~~29%~~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 ~~our~~each ~~total~~of ~~proved~~the ~~reserves~~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.

(2)Calculated using oil prices of $105.30, $105.13 and $108.48 per barrel, respectively, and natural gas prices of $3.73, $2.92 and $4.16 per Mcf, respectively, held constant for the life of the reserves, computed in accordance with ASC 932, based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the fiscal year (as required by ASC 932), applying historical adjustments, including transportation, quality differentials, and purchaser bonuses, on an individual property basis, to the year-end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price.


	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

(31)~~The~~ ~~present~~Net ~~value~~proved ofdeveloped ~~estimated~~non-producing ~~future net revenues attributable to our~~ reserves ~~was~~as ~~prepared~~of ~~using~~June ~~constant prices~~30, ~~determined~~2015 in(6,742 ~~the~~Mbbls ~~manner~~and ~~described~~37,123 inMmcf) ~~footnote~~were ~~(2)~~12,929 ~~discounted~~Mboe, ator a23% ~~rate~~ of ~~10% per~~our ~~year~~total onproved ~~a pre-tax basis~~reserves.

(42)~~The~~ ~~standardized~~Calculated ~~measure~~using oil price of ~~discounted~~$73.88 ~~future~~per ~~net~~barrel ~~cash~~and ~~flows~~natural ~~represents~~gas price of $3.11 per Mcf held constant for the ~~present~~life ~~value~~of the reserves, computed in accordance with ASC 932, based on the unweighted, arithmetic average of ~~future~~the ~~cash~~closing ~~flows~~price ~~after~~on ~~income~~the ~~taxes~~first ~~discounted~~day atof ~~10% per~~each of the twelve months during the fiscal year, asapplying ~~calculated~~historical inadjustments, ~~accordance~~including ~~with~~transportation, ~~SEC~~quality ~~guidelines~~differentials, and ~~pricing~~purchaser bonuses, on an individual property basis, to the year-end quantities of estimated proved reserves. The historical adjustments applied to the computed prices are determined by comparing our historical realized price experience with the comparable historical market, or posted, price.

(53)~~PV-10~~ isThe ~~considered~~present avalue ~~non-GAAP financial measure as defined by the SEC. We believe that the presentation~~ of ~~PV-10~~estimated ~~is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted~~ future net ~~cash~~revenues ~~flows~~ attributable to our ~~proved~~ reserves ~~before~~was ~~taking~~prepared ~~into~~using ~~account~~constant ~~future~~prices, ~~corporate~~determined ~~income~~in ~~taxes and our current tax structure. Because~~ the ~~standardized~~manner ~~measure~~described isin ~~dependent~~footnote ~~on the unique tax situation of each company~~(2), ~~our~~discounted ~~calculation~~at ~~may~~a ~~not~~rate ~~be comparable to those~~ of ~~our competitors. Because of this, PV-~~10% ~~can~~per beyear ~~used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves~~ on a ~~more~~pre-tax ~~comparable~~ basis.

6 (4) The standardized measure of discounted future net cash flows represents the present value of future cash flows after income taxes discounted at 10% per year, as calculated in accordance with SEC guidelines and pricing. However, we do not currently expect any future net income taxes due to our net operating loss carryforwards and our expectations regarding our future taxable income consistent with net losses recorded during the current fiscal year.

As(5) ofPV-10 ~~December~~is ~~31,~~considered ~~2013,~~a ~~our~~non-GAAP ~~PUDs~~financial ~~comprised~~measure 37as ~~drilling~~defined ~~locations~~by inthe ~~13 fields~~SEC. ~~The~~ ~~Ship~~We ~~Shoal~~believe ~~208~~that ~~field~~the ~~accounts~~presentation ~~for~~of ~~approximately~~PV-10 ~~50%~~is ofrelevant and useful to our ~~total~~investors ~~PUDs,~~as ~~with~~supplemental ~~11,495~~disclosure ~~Mboe~~to the standardized measure, ~~consisting~~or ofafter-tax 6amount,~~579~~ ~~Mbbls~~because ofit ~~oil~~presents ~~and~~the ~~29,496~~discounted ~~Mmcf~~future ofnet ~~natural~~cash ~~gas. The~~flows ~~remaining~~attributable 12to ~~locations~~our proved reserves before taking into account ~~for~~future ~~approximately~~corporate 1%income taxes and our current tax structure. Because the standardized measure is dependent on the unique tax situation of each company, our calculation may not be comparable to 8%those of our ~~total~~competitors. ~~PUDs~~Because ~~each~~of this, ~~with~~PV-10 ~~PUDs~~can ~~ranging~~be ~~from~~used ~~156~~within ~~Mboe~~the industry and by creditors and securities analysts to ~~1,959~~evaluate ~~Mboe.~~estimated net cash flows from proved reserves on a more comparable basis.

For the year ended December 31, 2013, the increase in our PUDs was primarily attributable to extensions and discoveries resulting in approximately 7,895 Mboe of proved reserves associated with 12 drilling locations. The Ship Shoal 208 field accounts for approximately 53% of our PUD extensions and discoveries with 4,152 Mboe, consisting of 3,541 Mbbls of oil and 3,668 Mmcf of natural gas in 5 locations. The remainder of our PUD extensions and discoveries were in five other fields with PUD extensions and discoveries ranging from 110 Mboe to 1,299 Mboe. During the year ended December 31, 2013, we divested 179 Mboe of PUDs in the Bay Marchand field and drilled two PUD locations in the West Delta area and one in the Ship Shoal 208 field. The three drilled PUD locations represent 1,675 Mboe, or approximately 9%, of our PUDs at December 31, 2012, consisting of 1,515 Mbbls of oil and 961 Mmcf of natural gas. We spent approximately $52 million drilling these three locations.

~~For~~TABLE ~~the~~OF year ended December 31, 2012, the acquisition of the Hilcorp Properties added PUDs of 15,472 Mboe. Other changes in our PUDs that occurred during the year ended December 31, 2012 were considered individually insignificant, netting to an increase of 419 Mboe. CONTENTS

WeChanges expect our PUDs as of December 31, 2013 of 23.1 Mmboe to begin converting from proved undeveloped to proved developed as the planned development projects begin in 2014.Proved We project future development costs relating to the development of the PUDs remaining at December 31, 2013 to be approximately $229 million in 2014, $52 million in 2015, $5 million in 2016 and $23 million thereafter. Reserves

Our ~~Vice~~proved ~~President,~~developed ~~Reserves, is the technical person primarily responsible for overseeing the preparation of our~~ reserve estimates ~~and~~decreased ~~for~~by ~~compliance with our policies~~18.4 HeMMBOE isor a30% ~~registered petroleum engineer with extensive experience in reservoir analysis and reports directly~~ to ~~our executive management~~43.7 AtMMBOE ~~the~~at ~~end~~June ~~of each year~~30, ~~our~~2015 ~~reserve~~from ~~estimates are prepared by outside petroleum engineering firms~~62.1 AsMMBOE ofat ~~December~~June 3130, ~~2013, our estimates of proved reserves are based on a reserve report prepared by the independent petroleum engineering firm NSAI, a nationally recognized engineering firm~~2014. AtThe ~~December~~decrease ~~31,~~was ~~2013,~~primarily ~~estimates~~due ~~of 100% of our total estimated net proved reserves were prepared by NSAI. NSAI’s report is filed as an exhibit~~ to ~~this Annual Report on Form 10-K.~~ :

~~NSAI~~• ~~provides~~Downward arevision ~~complete range~~ of ~~geological,~~3.6 ~~geophysical~~MMBOE, ~~petrophysical~~primarily ~~and~~due ~~engineering~~to ~~services and have~~ the ~~technical~~effect ~~experience and ability to perform these services in any~~ of ~~the~~reduced ~~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~~prices, ~~specifically those set forth by the SEC. NSAI’s report includes a description of the technical qualifications of the individuals at NSAI primarily responsible for preparing our reserve estimates.~~

We• ~~have~~Divestiture ~~internal controls in place to provide reasonable assurance~~ of ~~compliance with SEC rules in the determination of our reserve estimates~~11.0 ~~These~~MMBOE, ~~controls include:~~ and

•~~corporate~~ ~~policies~~Production ~~which~~of ~~require~~9.3 ~~reserve estimates to be in compliance with SEC guidelines;~~ MMBOE.

~~•data~~Offset ~~on new discoveries is reviewed~~ by ~~the Vice President, Reserves, and our outside engineering firm for evaluation and incorporation into our reserve estimates;~~ :

•~~year-end~~ ~~reserve~~Additions ~~estimates~~of ~~are~~2.9 ~~reviewed~~MMBOE, byprimarily ~~our~~from ~~Vice President~~drilling, ~~Reserves~~recompletions, and ~~our~~wells ~~chief~~returned ~~executive~~to ~~officer~~production ~~and~~that ~~other~~were ~~senior~~not ~~management;~~previously booked, more than 82% of which are from four fields: South Pass 78, South Pass 49, Ship Shoal 208 and West Delta 30, and

•~~revisions~~ ~~are~~Conversion ~~communicated~~of to2.6 ~~our~~MMBOE ~~board~~from ofproved ~~directors.~~undeveloped to proved developed reserves.

AsOur anproved ~~operator~~undeveloped ofreserve ~~domestic~~estimates ~~oil~~decreased ~~and~~by ~~gas~~13.9 ~~properties,~~MMBOE weor ~~have~~51% ~~filed~~to ~~Department~~13.5 ofMMBOE ~~Energy~~at ~~Form~~June ~~EIA-23~~30, ~~“Annual~~2015 ~~Survey~~from of27.4 ~~Oil~~MMBOE ~~and~~at ~~Gas~~June ~~Reserves~~30,” ~~as required by Public Law 93-275~~2014. The ~~differences~~decrease ~~between~~was ~~the~~primarily ~~reserves~~due ~~as reported on Form EIA-23 and those reported herein are attributable~~ to the fact that Form EIA-23 requires that an operator report the total reserves attributable to wells that it operates, without regard to percentage ownership and excluding non-operated wells in which it owns an interest. :

7 • Downward revisions of 11.2 MMBOE comprised of (i) 1.8 MMBOE due to the effect of reduced oil and gas prices, (ii) 2.8 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 6.6 MMBOE due to new data and field studies. Of the 6.6 MMBOE of downward revisions due to new data and field studies, more than 75% occurred in the following three fields: South Timbalier 26, South Pass 78 and Ship Shoal 208, and

~~The~~• ~~table~~Conversion ~~below sets forth production information for each field that contains 15% or more~~ of ~~our total proved reserves as of December 31, 2013~~2. ~~The~~6 ~~Ship~~MMBOE ~~Shoal~~from ~~208~~proved ~~field~~undeveloped ~~was~~to ~~acquired~~proved indeveloped ~~the Hilcorp Acquisition and the table below reflects production for this field beginning November 1, 2012~~reserves.

	Year Ended December 31,
	2013		2012		2011
Ship Shoal 208:
Oil (Mbbls)		658		109		-
Natural gas (Mmcf)		1,130		199		-
Total (Mboe)		846		142		-
East Bay:
Oil (Mbbls)		879		1,035		1,062
Natural gas (Mmcf)		90		47		76
Total (Mboe)		894		1,043		1,075
West Delta:
Oil (Mbbls)		2,293		1,142		775
Natural gas (Mmcf)		2,000		490		317
Total (Mboe)		2,626		1,224		828

Development of Proved Undeveloped Reserves

~~Costs~~Our ~~Incurred~~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 ~~Oil~~our ~~and~~June ~~Natural~~30, ~~Gas~~2014 ~~Activities~~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 ~~following~~relative ~~table~~portion ~~sets~~of ~~forth~~total PUD reserves that we develop over the ~~costs~~next ~~incurred~~five ~~associated~~years ~~with~~will ~~finding~~not be uniform from year to year, ~~acquiring~~but will vary by year depending on several factors; including financial targets such as reducing debt and/or ~~developing~~drilling ~~our~~within ~~proved~~cash ~~oil~~flow, drilling obligatory wells and ~~natural~~the ~~gas~~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.

	Year Ended December 31,
	2013		2012		2011
	(In thousands)
Acquisitions—Proved (1)	$	46,047	$	706,322	$	261,812
Acquisitions—Unproved		2,200		7,496		14
Exploration		46,100		43,338		17,129
Development (2)		303,245		180,938		83,577
Costs incurred	$	397,592	$	938,094	$	362,532

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.

(1)For the year ended December 31, 2013, includes $30 million associated with the acquisition of the Hilcorp Properties and $17 million associated with the acquisition of the WD29 Interests. See Note 2 “Acquisitions and Dispositions” of the consolidated financial statements in Part II, Item 8 of this Annual Report for further information. 6

~~(2)Includes~~TABLE ~~our~~OF estimates during the years ended December 31, 2013, 2012 and 2011 of incurred asset retirement obligations associated with finding and developing our proved oil and natural gas reserves of $1.2 million, $1.2 million and $0.2 million, respectively. CONTENTS

Productive Wells


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 ~~sets~~discloses ~~forth~~our progress toward the ~~number~~development of ~~productive~~PUD ~~oil~~reserves ~~and~~during ~~natural~~the ~~gas~~fiscal ~~wells~~year inended ~~which~~June ~~we owned an interest as of December 31~~30, ~~2013~~2015.

	Total Productive Wells
	Oil and Natural Gas				Future Development Costs
	Gross			Net
	(MBOE)				(in thousands)
Oil		379			314
Proved undeveloped reserves at June 30, 2014		27,386			$	402,604
Natural gas		98			72
Extensions and discoveries		250				7,750
Total		477			386
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

ProductiveQualifications wells consist of producingPrimary wellsInternal andEngineer wells capable of production, including oil wells awaiting connection to production facilities and naturalThird gasParty wells awaiting pipeline connections to commence deliveries. Thirty-seven gross oil wells and 11 gross natural gas wells have dual completions. Engineers

InEnergy ~~this~~XXI’s ~~Annual~~Director ~~Report~~of Reserves, ~~when~~Lee ~~referring~~I. toWilliams, ~~wells~~is ~~and~~the ~~acreage,~~technical ~~“gross”~~person ~~refers~~primarily toresponsible for overseeing the ~~total~~preparation ~~wells~~by orNSAI ~~acres~~of inour ~~which~~reserve weestimates ~~have~~and afor ~~working~~compliance ~~interest~~with Energy XXI’s policies. He has 15 years of industry experience with positions of increasing responsibility and ~~“net”~~has ~~refers~~over to10 ~~gross~~years’ ~~wells~~experience orin ~~acres~~the ~~multiplied~~estimation byand ~~our~~evaluation ~~working~~of ~~interest~~reserves. He graduated from Texas A&M University in 1998 with a Bachelor of Science Degree in Petroleum Engineering.

8 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.

~~Acreage~~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.

~~The~~Mr. ~~following~~Riseden ~~table~~has ~~sets~~been ~~forth~~practicing ~~information~~consulting ~~relating~~petroleum toengineering ~~acreage~~at ~~held~~NSAI bysince us2006. asMr. Riseden is a Licensed Professional Engineer in the State of ~~January~~Texas ~~15,~~(No. ~~2014~~100566) and has over 13 years of practical experience in petroleum engineering. ~~Developed~~He ~~acreage~~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 ~~assigned~~a toLicensed ~~producing~~Professional ~~wells~~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.

	Gross Acreage		Net Acreage
Developed:
Gulf of Mexico Shelf		319,375		237,659
Deepwater Gulf of Mexico		5,760		1,599
Other		125		125
Total		325,260		239,383
Undeveloped:
Gulf of Mexico Shelf		62,245		60,422
Deepwater Gulf of Mexico		34,560		9,663
Total		96,805		70,085

WeTABLE ~~continually~~OF assess our undeveloped lease inventory for exploration opportunities and, where appropriate, develop strategies to maintain our inventory by allocating resources to such leases or arranging for the participation of others, including farm-outs and the use of prospect generation consulting geologists. Leases covering 14% of our undeveloped net acreage expire in 2014, 8% expire in 2015, 10% expire in 2016, 39% expire in 2017, and 21% expire in 2018. The remaining undeveloped net acreage is held by production. We currently plan to develop opportunities for leases covering 48% of the net undeveloped acreage expiring in 2014. As of December 31, 2013, the total net book value of the leases expiring in 2014 and 2015 was $0.2 million. CONTENTS

~~Since~~Both ~~December~~technical ~~31,~~principals ~~2012,~~meet ~~our~~or ~~net~~exceed ~~developed~~the ~~acreage decreased 4~~education,~~589~~ ~~net acres~~training, ~~or 2%,~~ and ~~our~~experience ~~net~~requirements ~~undeveloped~~set ~~acreage~~forth ~~decreased 53,823 net acres, or 43%. The decrease~~ in ~~our~~the ~~net~~Standards ~~developed~~Pertaining ~~acreage was primarily attributable~~ to athe ~~decrease~~Estimating ofand ~~36,275~~Auditing ~~net acres, or 15%, associated with certain Gulf~~ of ~~Mexico~~Oil ~~shelf~~and ~~leases~~Gas ~~that~~Reserves ~~expired~~Information orpromulgated ~~were relinquished, which was substantially offset~~ by ~~an increase of 31,759 net acres, or 13%, primarily due to~~ the ~~Nexen~~Society ~~Acquisition and the development~~ of ~~certain~~Petroleum ~~leases~~Engineers; inboth ~~our~~are ~~West~~proficient ~~Delta and Main Pass fields. The decrease~~ in ~~our~~judiciously ~~net~~applying ~~undeveloped~~industry ~~acreage~~standard ~~was~~practices ~~primarily attributable~~ to ~~decreases~~engineering ~~totaling~~and ~~69,642~~geoscience ~~net~~evaluations ~~acres,~~as orwell ~~56%,~~as ~~primarily~~applying ~~associated~~SEC ~~with~~and ~~certain~~other ~~undeveloped~~industry ~~Gulf~~reserves ofdefinitions ~~Mexico shelf~~ and ~~deepwater Gulf of Mexico leases that expired or were relinquished~~guidelines. ~~The decrease was partially offset by the acquisition of new Gulf of Mexico shelf leases totaling 15,819 net acres, or 13%, resulting from recent federal lease sales.~~

DrillingTechnologies ActivityUsed in Reserve Estimation

~~Drilling~~The ~~activity~~SEC ~~refers~~allows touse ~~the~~of ~~number~~techniques ofthat ~~wells~~have ~~completed~~been atproved ~~any~~effective ~~time~~by ~~during~~actual production from projects in the ~~applicable~~same ~~fiscal~~reservoir ~~years,~~or ~~regardless~~an ofanalogous ~~when~~reservoir ~~drilling~~or ~~was~~by ~~initiated.~~other ~~The~~evidence ~~following~~using ~~table~~reliable ~~shows~~technology ~~our~~that ~~drilling~~establishes ~~activity~~reasonable ~~where~~certainty. The term “~~gross~~reasonable certainty” ~~refers~~is todefined by the ~~total~~SEC ~~wells~~as in“much ~~which~~more welikely ~~have~~to abe ~~working~~produced ~~interest~~than not” and “~~net~~much more likely to increase or remain constant than to decrease.” ~~refers~~Our internal reservoir engineers employed technologies that have been demonstrated to ~~gross~~yield ~~wells~~results ~~multiplied~~with byconsistency ~~our~~and ~~working~~repeatability. ~~interest~~The technologies used in ~~these~~the ~~wells.~~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.

	Year Ended December 31,
	2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net
Development Wells
Productive		13.0		11.5		11.0		9.5		4.0		3.6
Non-productive		3.0		3.0		1.0		1.0		1.0		1.0
Total		16.0		14.5		12.0		10.5		5.0		4.6
Exploratory Wells
Productive		-		-		1.0		0.8		4.0		1.3
Non-productive		1.0		1.0		2.0		0.7		1.0		0.5
Total		1.0		1.0		3.0		1.5		5.0		1.8
Recompletion Operations
Productive		17.0		14.4		16.0		14.2		23.0		19.1
Non-productive		4.0		3.7		2.0		2.0		4.0		3.3
Total		21.0		18.1		18.0		16.2		27.0		22.4

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

9 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.

We also drilled one gross (1.0 net) successful exploratory oil well in a recently-acquired primary term lease in our Main Pass 244 field that reached its target depth in September 2013 and is waiting on production facilities to commence production.


	Year Ended June 30, 2015		Six Months Ended June 30, 2014		Year Ended December 31,
	Year Ended June 30, 2015		Six Months Ended June 30, 2014		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

WeCosts areIncurred currently in theOil process of drilling five gross (5.0 net) development wells, three in our Ship Shoal 208 field, one in our West Delta area and oneNatural inGas our South Timbalier area. In addition, we recently drilled one exploratory well (0.5 net) in our Ship Shoal 208 field, which we are completing and anticipate first production in April 2014. Activities

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

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.


	Year Ended June 30, 2015		Six Months Ended June 30, 2014		Year Ended December 31,
	Year Ended June 30, 2015		Six Months Ended June 30, 2014		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

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. 8

~~Regulatory~~TABLE ~~Matters~~OF CONTENTS

OurOil operations are substantially affected by federal, state and localNatural lawsGas andProduction regulations. In particular, oil and gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. Prices

~~Regulation~~Our ofaverage ~~Natural~~daily ~~Gas~~production ~~Gathering.~~represents Section 1(b) of the Natural Gas Act of 1938, as amended (the “NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”) as a natural gas company under the NGA. We believe that our ~~natural~~net ~~gas~~ownership ~~pipelines~~ and ~~appurtenant~~includes ~~facilities~~royalty ~~meet~~interests the tests the FERC has historically used to establish a facility’s status as a gathering facility not subject to regulation as a natural gas company under the NGA. However, the distinction between FERC-regulated transmission facilities and ~~federally~~net ~~unregulated~~profit ~~gathering~~interests ~~facilities~~owned ~~is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations~~ by ~~the FERC, the courts, or Congress~~us. ~~Natural gas gathering facilities and operations may, at some point in the future, receive greater regulatory scrutiny at both the state and federal levels.~~ Our ~~natural~~average ~~gas~~daily ~~gathering~~production ~~operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates~~ and ~~services.~~average ~~Additional~~sales ~~rules~~prices ~~and legislation pertaining to these matters are considered or adopted from time to time~~follow. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Regulation of Offshore Gathering Facilities. Our gathering systems gather gas and oil on the Outer Continental Shelf (the “OCS”) and in Louisiana. Our gathering systems are subject to the jurisdiction of the applicable state regulatory agencies to the extent that those gathering systems traverse state land and/or waters. State regulation of gathering facilities generally includes a variety of safety, environmental, nondiscriminatory take, and common purchaser requirements, and complaint-based rate regulation.


	Year Ended June 30, 2015			Six Months Ended June 30, 2014			Year Ended December 31,
	Year Ended June 30, 2015			Six Months Ended June 30, 2014			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

TheProduction gatheringUnit systems are also subject to the jurisdiction of the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”), pursuant to The Outer Continental Shelf Lands Act (“OCSLA”), because they traverse the OCS pursuant to federal easements. As discussed herein, the BOEM and BSEE were created on October 1, 2011 to replace the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”) as part of a reorganization aimed at separating the resource management and enforcement functions of the former Minerals Management Service. OSCLA authorizes regulations governing the preparation of spill contingency plans and establishing air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to Costs

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

OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental prosecution or private action.


	Year Ended June 30, 2015		Six Months Ended June 30, 2014		Year Ended December 31,
	Year Ended June 30, 2015		Six Months Ended June 30, 2014		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

RegulationProductive of Onshore Gathering Facilities. Our onshore natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. The common purchaser statutes generally require our gathering pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer 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. Louisiana and Texas have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. The rates we charge for gathering in Texas and Louisiana are deemed just and reasonable unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal penalties. Wells

~~Though~~The ~~our~~following ~~natural~~table ~~gas~~sets ~~gathering~~forth ~~facilities are not subject to regulation by~~ the ~~FERC~~number ~~under the NGA, as the owner and operator~~ of ~~these~~productive ~~facilities,~~oil ~~we may be subject to certain annual natural gas transaction reporting requirements~~ and ~~daily scheduled flow and capacity posting requirements imposed by FERC depending on the volume of~~ natural gas ~~transactions~~wells ~~and flows on our facilities~~ in awhich ~~given~~we ~~period.~~owned ~~See~~an ~~the~~interest ~~discussion~~as of ~~“—Other~~June ~~Federal~~30, ~~Laws~~2015 and ~~Regulations Affecting Our Industry—FERC Market Transparency Rules~~2014.”

Regulation of Sales of Natural Gas and Natural Gas Liquids (“NGLs”). The price at which we buy and sell natural gas and NGLs is currently not subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC and/or the Commodity Future Trading Commission (“CFTC”). See below the discussion of “—Other Federal Laws and Regulations Affecting Our Industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities. In addition, some of our operations may be required to annually report to the FERC, information regarding natural gas purchase and sale transactions depending on the volume of natural gas purchased or sold during the prior calendar year. See below the discussion of “—Other Federal Laws and Regulations Affecting Our Industry—FERC Market Transparency Rules.”


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

~~Regulation~~In ofthis ~~Safety,~~Form ~~Availability~~10-K, ~~Terms~~when ~~and~~referring ~~Cost of Pipeline Transportation. Our onshore and offshore pipelines are subject~~ to ~~safety~~wells ~~regulation by the Pipeline~~ and ~~Hazardous~~acreage, ~~Materials Administration of the U.S. Department of Transportation (the~~ “~~PHMSA~~gross”), ~~BSEE~~refers ~~and/or~~to ~~state agencies, depending on~~ the ~~location~~total ~~and~~wells ~~services~~or ~~provided~~acres byin ~~each~~which ~~pipeline.~~we ~~Our~~have processing operations and our marketing of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. The price and terms of access to pipeline transportation can be subject to extensive federal and, if a ~~complaint~~working isinterest ~~filed, state regulation. The FERC regularly proposes~~ and ~~implements~~“net” ~~new~~refers ~~rules and regulations affecting the interstate transportation of natural gas, and~~ to agross ~~lesser~~wells ~~extent,~~or ~~the~~acres ~~interstate~~multiplied ~~transportation~~by ~~of NGLs. We cannot predict the ultimate impact of these regulatory changes to~~ our ~~natural~~working ~~gas production operations and our natural gas and NGL marketing operations~~interest. ~~We do not believe that we would be affected by any such FERC action in a materially different manner than other natural gas producers and natural gas and NGL marketers with whom we compete.~~

The ability of our facilities to deliver natural gas into third party natural gas pipeline facilities is directly impacted by the gas quality specifications required by those pipelines. In 2006, the FERC issued a policy statement on provisions governing gas quality and interchangeability in the tariffs of interstate gas pipeline companies and a separate order declining to set generic prescriptive national standards. In its policy statement on gas quality and interchangeability, the FERC encouraged all natural gas pipelines subject to its jurisdiction to use certain interim guidelines issued by a group of industry representatives, headed by the Natural Gas Council (the “NGC+ Work Group”), as the common reference point for resolving gas quality and interchangeability issues. We do not believe that the adoption of gas quality and interchangeability standards that are in line with the NGC+ Work Group’s interim guidelines by a pipeline that either directly or indirectly interconnects with our facilities would materially affect our operations. We cannot predict, however, whether FERC will approve gas quality specifications that materially differ from the NGC+ Work Group’s interim guidelines for such an interconnecting pipeline. 9

~~Regulation~~TABLE ofOF Transportation of Oil. Our wholly owned subsidiary, EPL Pipeline, L.L.C. (“EPL Pipeline”), is an interstate common carrier pipeline subject to regulation by the FERC under the Interstate Commerce Act (“ICA”). EPL Pipeline owns five pipelines subject to regulation by the FERC: (1) an approximately twelve-mile pipeline that runs between South Timbalier 26 and a portion of South Timbalier 41 on the Gulf of Mexico OCS to Bayou Fourchon, Louisiana; (2) an approximately eight-mile pipeline that runs between South Marsh Island Block 239 through Mound Point B and South Marsh Island Block 205 to Lighthouse Point A, South Marsh Island Block 207 on the Gulf of Mexico OCS to Vermillion Parish, Louisiana; (3) an approximately nine-mile pipeline that runs between South Pass Block 78 and South Pass Block 55 on the CONTENTS

11 Acreage

Gulf of Mexico OCS; and (4) an approximately ten-mile pipeline that runs between South Pass Block 55 and West Delta Block 83 on the Gulf of Mexico OCS to Plaquemines Parish, Louisiana; and (5) an approximately ten-mile pipeline that runs between Vermillion Block 38 to a point of interconnection designated as the EPL Pipeline Vermillion Block 38 Lateral Interconnect. The ~~ICA~~following ~~requires~~table ~~that~~sets ~~we maintain tariffs on file with the FERC for these pipelines. The tariffs set~~ forth ~~the~~information ~~rates,~~relating ~~which~~to ~~were~~acreage ~~established~~held asby ~~negotiated~~us ~~rates that have not been protested,~~ as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier pipelines be “just and reasonable” and nondiscriminatory. The ICA permits challenges to existing rates and authorizes the FERC to investigate such rates to determine whether they are just and reasonable. If a challenge is made to a newly filed increased rate and FERC ultimately finds that the proposed rate is unlawful following an investigation, FERC is permitted to change that rate prospectively from the date of ~~its~~June ~~decision~~30, ~~and may order refunds representing the difference between the challenged increased rate and the previous lawful rate~~2015. If aDeveloped ~~complaint~~acreage is ~~filed~~assigned ~~against an existing rate, FERC may award reparations for the two year period prior~~ to ~~the~~producing ~~date of the complaint~~wells.

Other Federal Laws and Regulations Affecting Our Industry


	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

~~Energy~~During ~~Policy~~fiscal ~~Act~~years of2016 ~~2005. The Energy Policy Act of 2005 (“EPAct 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants~~ and ~~guaranteed loans~~2017, ~~and~~we ~~significant~~do ~~changes~~not tohave ~~the~~any ~~statutory~~leases ~~policy~~covering that affects all segments of the energy industry. With respect to regulation of natural gas transportation, EPAct 2005 amended the NGA by increasing the criminal penalties available for violations of each Act. EPAct 2005 also added a new section to the NGA that provides the FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce, including our ~~Company.~~undeveloped ~~EPAct~~acreage ~~2005~~expiring; also amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by the FERC. FERC’s regulations make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERChowever, orduring ~~the~~fiscal ~~purchase~~year ~~or sale of transportation services subject to the jurisdiction of the FERC~~2018, ~~for~~leases ~~any~~covering ~~entity~~42,903 ~~directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement~~ of ~~material~~our ~~fact~~undeveloped orgross ~~omit~~acreage ~~any statement necessary to make the statements made not misleading; or~~ (~~3) to engage in any act or practice that operates as a fraud or deceit upon any entity. The regulations do not directly apply to activities that relate only to non-jurisdictional sales or gathering~~32,697 but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities (including those which engage in non-jurisdictional sales or gatheringnet) towill the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements and daily scheduled flowsexpire.

~~FERC~~Drilling ~~Market~~Activity Transparency Rules. FERC’s regulations require wholesale buyers and sellers of more than 2.2 MmBtu of physical natural gas in the previous calendar year (including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas 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.

~~Additional~~Drilling ~~proposals~~activity ~~and~~refers ~~proceedings~~to ~~that might affect~~ the ~~natural~~number ~~gas~~of ~~industry~~wells ~~are~~completed ~~pending~~at ~~before~~any ~~Congress,~~time ~~FERC~~during ~~and~~ the ~~courts.~~applicable Wefiscal ~~cannot~~years, ~~predict~~regardless ~~the ultimate impact~~ of ~~these~~when ordrilling ~~the~~was ~~above~~initiated. ~~regulatory~~The ~~changes~~following totable shows our ~~natural~~drilling ~~gas~~activity ~~operations.~~where We“gross” dorefers ~~not~~to ~~believe~~the ~~that~~total wewells ~~would~~in bewhich ~~affected~~we byhave ~~any~~a ~~such~~working ~~actions~~interest onand a“net” ~~materially~~refers ~~different~~to ~~basis~~gross ~~than~~wells ~~other~~multiplied ~~natural~~by ~~gas~~our ~~companies~~working ~~with~~interest ~~whom~~in wethese ~~compete~~wells.

Environmental Matters


	Year Ended June 30, 2015				Six Months Ended June 30, 2014				Year Ended December 31,
	Year Ended June 30, 2015				Six Months Ended June 30, 2014				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

General.Present Various federal, state and local laws and regulations governing the protection of the environment, such as the Oil Pollution Act of 1990 (“OPA”), the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (“CERCLA”), the Resource Conservation and Recovery Act, as amended (“RCRA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”), affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons, and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state laws and regulations. These laws and regulations: Activities

~~•restrict~~As ~~the types, quantities and concentration~~ of ~~various~~June ~~substances~~30, ~~that~~2015, ~~can~~we bewere ~~released~~not ~~into the environment~~ in ~~connection with drilling and production activities and establish requirements for~~ the ~~management~~process ~~and disposal~~ of ~~drill~~drilling ~~production~~any ~~water~~wells. ~~and wastes;~~

•limitDelivery or prohibit drilling and production activities on certain lands lying within wetlands and other protected areas and in ways that affect certain species; Commitments

~~•impose~~We ~~permitting,~~had ~~monitoring,~~no ~~and~~delivery ~~recordkeeping~~commitments ~~requirements~~in ~~and~~the ~~other~~three ~~regulatory~~years ~~controls;~~ended ~~and~~June 30, 2015.

12 Title to Properties

~~•impose~~Our ~~substantial~~properties ~~liabilities~~are subject to customary royalty interests, ~~including~~liens ~~cleanup~~under ~~obligations~~indebtedness, liens incident to operating agreements, mechanics’ and materialman’s liens, liens for ~~pollution~~current taxes and ~~natural~~other ~~resource~~burdens, ~~damages~~including ~~resulting~~other ~~from~~mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with the use of our ~~operations~~properties or the operation of our business.

~~Failure~~We tobelieve ~~comply~~that ~~with~~we ~~these~~have ~~laws~~satisfactory ~~and~~title ~~regulations~~to, ~~could~~or ~~result~~rights in, ~~the~~all ~~assessment~~ of ~~significant~~our ~~administrative,~~properties. ~~civil~~As ~~and~~is ~~criminal~~customary ~~fines~~in ~~and penalties,~~ the ~~incurrence~~oil ofand ~~capital~~natural ~~expenditures,~~gas ~~delays in the development of projects~~industry, ~~the~~minimal ~~imposition~~investigation of ~~remedial~~title oris ~~corrective~~made ~~action~~at ~~obligations, or injunctive relief that could include limitations on, or~~ the ~~cessation~~time of, ~~certain~~acquisition of ~~our~~undeveloped ~~operations~~properties. ~~Changes~~We ininvestigate ~~environmental~~title ~~laws~~prior ~~and~~to ~~regulations occur regularly and~~ the ~~current~~consummation ~~trend~~of isan ~~toward~~acquisition ~~more~~of ~~stringent~~producing ~~environmental~~properties ~~regulation~~ and ~~legislation.~~before Wethe ~~believe~~commencement ~~that~~of wedrilling ~~are~~operations inon ~~substantial~~undeveloped ~~compliance~~properties. ~~with~~We ~~currently~~have ~~applicable~~obtained ~~environmental~~or ~~laws~~conducted ~~and regulations and that continued compliance with existing requirements will not have~~ a ~~material~~thorough ~~adverse~~title ~~impact~~review on ~~us. For~~substantially ~~example,~~all ~~we did not incur any material capital expenditures for remediation or pollution control activities for the year ended December 31, 2013, and we are not aware~~ of ~~any environmental issues or claims that will require material capital expenditures during 2014. Nevertheless, accidental spills or releases may occur in the course of~~ our ~~operations,~~producing properties and webelieve ~~cannot give any assurances~~ that we ~~will~~have ~~not~~satisfactory ~~incur~~title ~~substantial~~to ~~costs and liabilities, as a result of~~ such ~~spills~~properties orin ~~releases,~~accordance ~~which~~with ~~would~~standards ~~not~~generally beaccepted covered by insurance, including those relating to claims for damage to property and persons. Moreover, we cannot give any assurance that the passage of more stringent or additional laws or regulations in the ~~future~~oil ~~will not materially adversely affect our business, results of operations~~ and ~~financial~~natural gas ~~condition~~industry.

OilGovernment Pollution Act of 1990. The OPA, and regulations thereunder, impose significant liability on “responsible parties” for removal costs and damages resulting from oil spills into or upon navigable waters, adjoining shorelines, or in the exclusive economic zone of the United States, including the OCS waters where we have substantial operations. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. OPA also requires that the lessee or permittee of the offshore area in which a covered offshore facility is located establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. Regulation

AOur ~~failure~~oil toand ~~comply~~gas ~~with~~exploration, ~~OPA’s~~production ~~requirements~~and orrelated ~~inadequate~~operations ~~cooperation~~and ~~during~~activities aare ~~spill~~subject ~~response~~to ~~action~~extensive ~~may~~rules ~~subject~~and aregulations ~~responsible~~promulgated ~~party~~by tofederal, ~~civil~~state orand ~~criminal~~local ~~enforcement~~governmental ~~actions,~~agencies. ~~including~~Failure ~~penalties~~to ~~and~~comply ~~natural~~with ~~resource~~such ~~damages.~~

We are not aware of the occurrence of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s current financial responsibility and other operating requirements will not have a material adverse effect on us. 10

~~Superfund.~~TABLE ~~CERCLA,~~OF also known as Superfund, and comparable state laws impose strict liability for response costs associated with releases of “hazardous substances” and damages to natural resources as a result of such releases, without regard to fault or the legality of the original act, on certain classes of persons. These persons include the current or former “owner” or “operator” of a disposal site or a site where a release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CONTENTS

~~While~~rules ~~the~~and ~~term~~regulations ~~“hazardous~~can ~~substance”~~result ~~under~~in ~~CERCLA~~substantial ~~does~~penalties. ~~not~~Because ~~include~~such ~~petroleum,~~rules ~~natural~~and ~~gas,~~regulations ~~NGLs,~~are ~~liquefied~~frequently ~~natural~~amended ~~gas,~~ or ~~synthetic gas usable for fuel~~reinterpreted, we ~~may~~are ~~generate~~unable ~~wastes~~to ~~that~~predict ~~fall within CERCLA’s definition of a “hazardous substance” in~~ the ~~course~~future ofcost ~~our ordinary operations. We also own~~ or ~~lease~~impact ~~properties~~of ~~that~~complying ~~for~~with ~~many~~such ~~years~~laws. ~~have~~Although ~~been used for~~ the ~~exploration~~regulatory ~~and~~burden ~~production~~on ofthe oil and ~~natural~~ gas. ~~Although~~industry weincreases ~~and, to~~ our ~~knowledge,~~cost ~~our~~of ~~predecessors~~doing ~~have~~business ~~used operating~~ and ~~disposal practices that were standard in the industry at the time~~, ~~we may still be responsible if “hazardous substances” were disposed or released on~~consequently, ~~under~~affects orour ~~from these properties or on~~profitability, ~~under or from other locations where~~ these ~~wastes~~burdens ~~have~~generally ~~been~~do ~~taken~~not ~~for~~affect ~~disposal.~~us ~~CERCLA~~any ~~authorizes~~differently ~~the~~or ~~federal Environmental Protection Agency (“EPA”) and, in some instances, third parties~~ to ~~act~~any ingreater ~~response to threats to the public health~~ or ~~the~~lesser ~~environment~~extent ~~and~~than ~~to seek to recover from responsible parties the costs~~ they ~~incur.~~affect Atothers ~~this~~in ~~time,~~our weindustry ~~do not believe that we have any liability associated~~ with ~~any~~similar ~~Superfund site~~types, quantities and welocations ~~have not been notified~~ of ~~any claim, liability or damages under CERCLA~~production.

~~Resource~~Regulations ~~Conservation~~affecting ~~and Recovery Act~~production. The ~~RCRA~~jurisdictions ~~and~~in ~~comparable~~which ~~state~~we ~~laws~~operate ~~impose~~generally ~~detailed~~require ~~requirements~~permits ~~relating~~for todrilling ~~the handling~~operations, ~~storage,~~drilling ~~treatment~~bonds and ~~disposal~~operating ofreports ~~hazardous~~and ~~waste.~~impose Weother ~~routinely~~requirements ~~generate~~relating ~~small~~to ~~quantities of hazardous waste in~~ the ~~ordinary~~exploration ~~course~~and production of ~~our~~oil ~~business~~and ~~that are subject to these requirements~~gas. ~~These~~Such ~~wastes~~jurisdictions ~~are~~also ~~treated,~~have ~~stored~~statutes ~~and~~or ~~disposed~~regulations ofaddressing ~~off-site~~conservation ~~at facilities that are permitted to manage them. At present~~matters, ~~RCRA~~including ~~and~~provisions ~~many~~for ~~similar~~the ~~state~~unitization ~~statutes~~or ~~include~~pooling aof ~~statutory exemption that allows most~~ oil and ~~natural~~ gas ~~exploration~~properties, ~~and production waste to be classified as nonhazardous waste. At various times in~~ the ~~past,~~establishment ~~proposals~~of ~~have~~maximum ~~been~~rates ~~made~~of toproduction ~~amend~~from ~~RCRA to rescind the exemption that excludes~~ oil and ~~natural~~ gas ~~exploration~~wells, ~~and~~the ~~production~~spacing, ~~wastes~~plugging ~~from~~and ~~regulation~~abandonment ~~as hazardous waste. Repeal or modification~~ of ~~the~~such ~~current exemption by administrative~~wells, ~~legislative~~restrictions oron ~~judicial~~venting ~~process,~~ or ~~modification~~flaring ofnatural ~~similar~~gas ~~exemptions~~and inrequirements ~~applicable state statutes, would increase~~ regarding the ~~volume~~ratability of ~~hazardous waste we are required to manage and dispose of and would cause us to incur increased operating expenses~~production.

13 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.

~~Clean~~In ~~Water~~the ~~Act.~~event ~~The~~we ~~Clean~~conduct ~~Water~~operations ~~Act imposes restrictions and controls~~ on ~~the discharge of pollutants~~federal, ~~including petroleum, produced water and other certain wastes into navigable waters, including coastal waters. Permits must be obtained to discharge pollutants into~~ state ~~and~~or ~~federal~~Indian waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas ~~industry into certain coastal and offshore waters. Further~~leases, ~~the~~our ~~EPA~~operations ~~has~~may ~~adopted~~be ~~regulations~~required ~~requiring certain oil and natural gas exploration and production facilities~~ to ~~obtain~~comply ~~permits for storm water discharges. Costs may be associated~~ with ~~the~~additional ~~treatment~~regulatory ~~of wastewater or~~restrictions, toincluding avarious ~~lesser~~nondiscrimination ~~degree~~statutes, ~~developing~~royalty and ~~implementing~~related ~~storm~~valuation ~~water pollution prevention plans. The Clean Water Act and comparable state statutes provide for significant civil~~requirements, ~~criminal~~ and ~~administrative~~on-site ~~penalties~~security ~~for~~regulations ~~unauthorized discharges of oil~~ and other ~~pollutants~~appropriate orpermits ~~unauthorized~~issued ~~discharges~~by ofthe ~~pollutants~~Bureau orof ~~fill~~Land ~~material~~Management ~~into~~(“BLM”) ~~wetlands~~ or other ~~waters.~~relevant ~~These~~federal ~~statutes~~or also impose liability for cleanup, restoration and damages on the parties responsible for those discharges. We are subject to the Clean Water Act’s permitting requirements for discharges associated with exploration and development activities. We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state ~~statutes enacted to control water pollution~~agencies.

~~Safe~~Regulations ~~Drinking~~affecting ~~Water Act~~sales. The ~~underground~~sales ~~injection~~prices of oil, natural gas liquids and natural gas ~~wastes~~ are ~~regulated~~not bypresently ~~the~~regulated ~~Underground~~but ~~Injection~~rather ~~Control~~are ~~Program,~~set ~~authorized~~ by the ~~Safe Drinking Water Act~~market. ~~The~~We ~~primary~~cannot ~~objective~~predict, ofhowever, ~~injection~~whether ~~well~~new ~~operating~~legislation ~~requirements is~~ to ~~ensure~~regulate the ~~mechanical~~price ~~integrity~~ of ~~the~~energy ~~injection~~commodities ~~apparatus~~might ~~and~~be toproposed, ~~prevent~~what ~~migration~~proposals, ofif ~~fluids from the injection zone into underground sources of drinking water. In Louisiana and Texas~~any, nomight ~~underground~~actually ~~injection~~be ~~may~~enacted ~~take place except as authorized~~ by ~~permit~~Congress or ~~rule.~~the ~~We currently own and operate~~ various ~~underground~~state ~~injection~~legislatures, ~~wells. Failure to comply with our permits could subject us to civil~~ and~~/or~~ ~~criminal~~what ~~enforcement.~~effect, Weif ~~believe~~any, ~~that~~the weproposals ~~are~~might inhave ~~compliance~~on ~~in all material respects with~~ the ~~requirements~~operations of ~~applicable~~the ~~state~~underlying ~~underground injection control programs and our permits~~properties.

~~National~~The ~~Marine~~Federal ~~Sanctuary~~Energy ~~Act,~~Regulatory ~~Marine~~Commission ~~Mammal~~(“FERC”) ~~Protection~~regulates ~~Act,~~interstate ~~Migratory~~natural ~~Bird~~gas ~~Treaty~~pipeline ~~Act,~~transportation rates and ~~Endangered~~service ~~Species~~conditions, ~~Act.~~which ~~Certain~~affect ~~federal~~the ~~laws,~~marketing ~~including~~of ~~the~~gas ~~National~~we ~~Marine~~produce, ~~Sanctuary~~as ~~Act,~~well as the ~~Marine~~revenues ~~Mammal~~we ~~Protection~~receive ~~Act,~~for ~~the~~sales ~~Migratory~~of ~~Bird~~such ~~Treaty~~production. ~~Act~~The price and ~~the~~terms ~~Endangered~~of ~~Species~~access ~~Act,~~to ~~provide~~pipeline ~~special~~transportation ~~protection~~are subject to ~~certain~~extensive ~~designated~~federal ~~marine areas~~ and ~~marine~~state ~~species~~regulation. ~~These~~FERC ~~laws~~is ~~and~~continually ~~their~~proposing ~~state~~and ~~equivalents~~implementing ~~provide~~new ~~for~~rules ~~significant civil~~ and ~~criminal~~regulations ~~penalties~~affecting ~~for~~interstate ~~unpermitted~~transportation. ~~activities~~These ~~that~~initiatives ~~result~~also inmay ~~harm~~affect tothe orintrastate ~~harassment~~transportation of natural gas under certain ~~protected~~circumstances. ~~plants~~The ~~and~~stated ~~animals,~~purpose ~~including~~of ~~damage~~many of these regulatory changes is to ~~their~~promote ~~habitats.~~competition ~~Further,~~among ifthe ~~such~~various ~~species~~sectors ~~are~~of ~~located~~the innatural angas ~~area~~industry. inWe ~~which~~do not believe that we ~~conduct~~will ~~operations,~~be ~~our~~affected ~~operations~~by ~~could~~any besuch ~~prohibited,~~FERC ~~restricted,~~action orin ~~delayed,~~a ormanner wematerially ~~could~~differently bethan ~~required~~other tonatural ~~implement~~gas ~~expensive~~producers ~~mitigation~~in ~~measures~~our areas of operation.

InThe ~~addition,~~price ~~Executive~~we ~~Order~~receive ~~13158~~from ~~(Marine~~the ~~Protected~~sale ~~Areas),~~of ~~issued~~oil inand ~~2000,~~natural ~~directs~~gas ~~federal~~liquids ~~agencies~~is toaffected ~~strengthen~~by ~~existing~~the ~~Marine~~cost ~~Protected~~of ~~Areas~~transporting ~~(“MPAs”),~~those ~~establishes~~products ~~new~~to ~~MPAs,~~market. ~~and~~Rates ~~develops~~charged aand ~~national~~terms ~~system~~ of ~~MPAs.~~service ~~This~~for ~~order~~the ~~could~~interstate ~~adversely~~pipeline ~~affect~~transportation ~~our~~of ~~operations~~oil, bynatural ~~restricting~~gas ~~areas~~liquids inand ~~which~~other werefined ~~may~~petroleum ~~carry~~products ~~out~~also ~~future~~are ~~exploration~~regulated orby ~~production activities and/or cause us to incur increased operating expenses~~FERC. InFERC ~~addition,~~has ~~federal~~established ~~permit~~an ~~approvals~~indexing ~~are~~methodology ~~conditioned~~for onchanging the ~~collection~~interstate ~~and~~transportation ~~removal~~rates offor ~~debris~~oil ~~resulting~~pipelines, ~~from~~which ~~activities~~allows ~~related~~such pipelines to ~~exploration,~~take ~~development~~an ~~and~~annual ~~production~~inflation-based ofrate ~~offshore~~increase. ~~leases~~We inare ~~order~~not able to ~~prevent~~predict ~~harm~~with toany ~~marine~~certainty ~~species.~~what ~~The~~effect, ~~BSEE~~if ~~also~~any, ~~issues~~these ~~Notices~~regulations towill ~~Lessees~~have ~~and~~on ~~Operators~~us, ~~(“NTLs”)~~but, ~~that~~other ~~provide~~factors ~~guidance~~being onequal, the regulations ~~implementation~~may, ofover ~~and~~time, ~~compliance~~tend ~~with~~to ~~OCSLA~~increase ~~regulations.~~transportation ~~Many~~costs ofwhich ~~these~~may ~~NTLs,~~have ~~with~~the ~~which~~effect weof ~~must~~reducing ~~comply,~~wellhead ~~relate~~prices tofor ~~the~~oil ~~prevention~~and ofnatural ~~harm~~gas ~~to marine species~~liquids.

~~Consideration~~Market ofmanipulation ~~Environmental~~and ~~Issues~~market intransparency ~~Connection~~regulations. Under ~~with~~the ~~Governmental~~Energy ~~Approvals.~~Policy ~~Our~~Act ~~operations~~of ~~frequently~~2005 ~~require~~(“EPAct ~~federal licenses~~2005”), ~~permits,~~FERC ~~and/or~~possesses ~~other~~regulatory ~~governmental~~oversight ~~approvals.~~over ~~Several~~natural ~~federal~~gas ~~statutes~~markets, including ~~OCSLA,~~ the ~~National Environmental Policy Act~~purchase, sale and ~~the~~transportation ~~Coastal~~of ~~Zone~~natural ~~Management~~gas ~~Act~~by ~~require~~“any ~~federal~~entity” ~~agencies~~in order to ~~evaluate~~enforce ~~environmental~~the ~~issues~~anti-market inmanipulation ~~connection~~provisions ~~with~~in ~~granting~~the ~~such~~EPAct ~~approvals~~2005. ~~and/or~~The ~~taking~~Commodity ~~other~~Futures ~~major~~Trading ~~agency~~Commission ~~actions.~~(“CFTC”) ~~The~~also ~~environmental~~holds ~~review~~authority ~~process~~to ~~required~~regulate ~~under~~certain ~~these~~segments ~~laws~~of ~~can~~the bephysical ~~costly~~ and ~~time-consuming,~~futures ~~are~~energy ~~increasingly~~commodities ~~the~~market ~~subject~~pursuant ofto ~~citizen~~the ~~group~~Commodity ~~intervention~~Exchange ~~and~~Act. ~~challenge~~Likewise, ~~and~~the ~~could~~Federal ~~result~~Trade inCommission ~~the~~(“FTC”) ~~delay~~holds authority orto ~~prohibition~~regulate ofwholesale ~~our~~petroleum ~~planned activities.~~

Lead-Based Paints. Various pieces of equipment and structures owned by us have been coated with lead-based paints as was customary in the industry at the time these pieces of equipment were fabricated and constructed. These paints may contain lead at a concentration high enough to be considered a regulated hazardous waste when removed. If we need to remove such paints in connection with maintenance or other activities and they qualify as a regulated hazardous waste, this would increase the cost of disposal. High lead levels in the paint may also require us to institute certain administrative and/or engineering controls required by the Occupational Safety and Health Act and the BSEE to ensure worker safety during paint removal. 11

~~Clean~~TABLE ~~Air~~OF Act. Our operations utilize equipment that emits air pollutants subject to the federal Clean Air Act and state air pollution control laws. These laws limit the emissions of regulated pollutants from such equipment and, in some instances, require the installation and operation of pollution control equipment to achieve these emissions limitations and meet ambient air quality standards. These laws also require us to maintain operating permits for existing equipment and obtain construction permits for new and modified equipment. EPA continues to consider and promulgate new or revised regulations under the Clean Air Act, such as the recently revised New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants applicable to the oil and gas industry sector, that generally impose more stringent regulations upon aspects of our business. We could be required to incur costs in the future to make operational changes or to purchase CONTENTS

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 14 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.

~~additional~~FERC ~~air~~has ~~pollution~~issued ~~control~~certain ~~equipment~~market intransparency ~~order~~rules pursuant to ~~comply~~its ~~with~~EPAct ~~these~~2005 ~~changing regulations~~authority, ~~although~~which wemay doaffect ~~not~~some ~~believe~~or ~~that~~all ~~such~~of ~~requirements~~our ~~will~~operations. ~~have~~FERC issued a ~~material~~final ~~adverse~~rule ~~effect~~in 2007, as amended by subsequent orders on ~~our~~rehearing ~~operations~~(“Order 704”), which requires wholesale buyers and sellers of more than 2.2 Wemillion ~~believe~~MMBtu ~~that~~of wephysical ~~are~~natural gas in ~~compliance~~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 ~~all~~the ~~material~~prior ~~respects~~calendar ~~with~~year ~~currently~~to ~~applicable~~the ~~air~~extent ~~pollution~~such ~~control~~transactions ~~laws~~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, ~~requirements~~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.

~~Climate~~Oil ~~Change~~Pipeline Regulations. We ~~Scientific~~own ~~studies~~interests ~~have~~in ~~suggested~~oil ~~that~~pipelines ~~emissions~~regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of ~~certain~~1992 (“~~greenhouse~~EPAct ~~gases,~~of 1992”), ~~including~~and ~~carbon~~the ~~dioxide~~rules and ~~methane~~regulations promulgated under those laws and, ~~may~~thus, behave ~~contributing~~interstate totariffs ~~warming~~on offile ~~the~~with ~~Earth’s~~FERC ~~atmosphere.~~setting ~~International~~forth ~~negotiations~~our tointerstate ~~address~~transportation ~~climate~~rates ~~change~~and ~~have~~charges ~~occurred~~and inthe ~~response~~rules and regulations applicable to ~~such~~our ~~studies~~jurisdictional transportation service. InThe ~~2009~~ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, ~~the~~including ~~United~~interstate ~~States~~pipelines ~~submitted~~that atransport ~~non-binding~~crude ~~greenhouse~~oil, natural gas ~~emission~~liquids ~~reduction~~and ~~target~~refined ofpetroleum 17products ~~percent~~pipelines, ~~compared~~be tojust ~~2005~~and ~~levels~~reasonable ~~pursuant~~and tonon-discriminatory ~~the~~and ~~Copenhagen~~that ~~Accord~~such rates and ~~negotiations~~terms ~~continue~~and ~~under~~conditions of service be filed with FERC. Under the ~~United~~ICA, ~~Nations~~shippers ~~Framework~~may ~~Convention~~challenge onnew ~~Climate~~or ~~Change~~existing rates or services. InFERC is authorized to suspend the ~~United~~effectiveness ~~States,~~of ~~Congress~~a ~~has~~challenged ~~considered~~rate ~~legislation~~for up to ~~reduce~~seven ~~emissions~~months, ofthough ~~greenhouse~~rates ~~gases;~~are ~~however,~~typically nonot ~~such~~suspended ~~legislation~~for ~~has~~the ~~been~~maximum ~~passed~~allowable period. ItA issuccessful ~~uncertain~~rate atchallenge ~~this~~could ~~time~~result ~~whether,~~in ~~and~~an oil pipeline paying refunds for the period that the rate was in ~~what~~effect ~~form,~~and/or ~~federal~~reparations ~~climate~~for ~~change~~up ~~legislation~~to ~~will~~two beyears ~~adopted~~prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.

InUnder the ~~absence~~EPAct of ~~over~~1992, oil pipeline rates in effect for the 365-~~arching~~day ~~federal~~period ~~climate~~ending ~~change~~on ~~legislation~~the date of enactment of the EPAct of 1992 are deemed to be just and reasonable under the ICA, ~~many~~ ~~states~~if such rates were not subject to complaint, protest or investigation during that 365-day period. These rates are ~~regulating~~commonly ~~greenhouse~~referred ~~gas~~to ~~emissions~~as “grandfathered rates.” ~~Certain~~FERC ~~states,~~may change grandfathered rates upon complaint only after it is shown that (i) a substantial change has occurred since enactment in either ~~individually~~the economic circumstances or ~~through~~the ~~multi-state~~nature ~~regional~~of ~~initiatives,~~the ~~have~~services ~~passed~~that ~~laws,~~were ~~adopted~~a ~~regulations~~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 ~~undertaken~~(iii) ~~regulatory~~a ~~activity~~provision of the tariff is unduly discriminatory or preferential. The EPAct of 1992 places no similar limits on challenges to ~~reduce~~a ~~emissions~~provision of ~~greenhouse~~an ~~gases~~oil pipeline tariff as unduly discriminatory or preferential.

The ~~EPA~~EPAct isof ~~also~~1992 ~~regulating~~further ~~greenhouse~~required ~~gas~~FERC ~~emissions~~to ~~from~~establish ~~both~~a ~~mobile~~simplified and ~~certain~~generally ~~large~~applicable ~~stationary~~ratemaking ~~sources~~methodology ~~under~~for ~~its~~interstate ~~existing~~oil ~~authority~~pipelines. ~~pursuant~~As toa ~~the~~result, ~~Clean~~FERC ~~Air~~adopted ~~Act.~~an Inindexing ~~2009,~~rate ~~the~~methodology ~~EPA~~which, ~~published~~as ~~its~~currently ~~finding~~in ~~that~~effect, ~~greenhouse~~allows ~~gases~~oil ~~contribute~~pipelines to ~~air~~change ~~pollution~~their rates within prescribed ceiling levels that ~~may~~are ~~endanger~~tied ~~public~~to ~~health~~changes orin ~~welfare~~the Producer Price Index for Finished Goods, plus 2.65 ~~Thereafter~~percent. Rate increases made under the index are subject to protest, but the ~~EPA~~scope ~~promulgated~~of ~~regulations~~the ~~requiring~~protest ~~that~~proceeding ~~major~~is ~~sources~~limited into an inquiry into whether the ~~United~~portion ~~States~~of ~~collect~~the ~~and~~rate ~~report~~increase ~~information~~resulting ~~regarding~~from ~~greenhouse~~application ~~gas~~of ~~emissions.~~the ~~For~~index ~~petroleum~~is ~~and~~substantially ~~natural~~in excess ~~gas~~of ~~facilities,~~the ~~including~~pipeline’s ~~offshore~~increase ~~petroleum~~in ~~and~~costs. ~~natural~~The ~~gas~~indexing ~~production~~methodology ~~facilities~~is ~~that~~applicable ~~emit~~to 25any existing rate,~~000~~ ~~metric~~including ~~tons~~a orgrandfathered ~~more~~rate. ofIndexing ~~carbon~~includes ~~dioxide~~the ~~equivalent~~requirement ~~per~~that, in any year, ~~data~~in ~~collection~~which ~~began~~the onindex ~~January 1~~is negative, ~~2011~~pipelines ~~and~~must ~~the~~file ~~first~~to ~~annual~~lower ~~reports~~their ~~were~~rates ~~due~~if onthose ~~March 31,~~rates ~~2012.~~would Inotherwise ~~January~~be ~~2011~~above the rate ceiling. However, ~~new~~the ~~EPA~~pipeline ~~permitting~~is ~~requirements~~not ~~became~~required ~~effective~~to ~~for~~reduce ~~greenhouse~~its ~~gas~~rates ~~emissions~~below ~~from~~the ~~new~~level deemed just and ~~modified~~reasonable ~~large~~under ~~stationary~~the ~~sources~~EPAct of 1992.

Courts are addressing climate change issues as well. Many of the EPA’s greenhouse gas rules are undergoing legal challenges and numerous other challenges are being filed by groups seeking additional regulation of a variety of additional sources of greenhouse gas emissions. On June 20, 2011, the U.S. Supreme Court issued a decision that bars state and private parties from bringing federal common law nuisance actions against certain energy companies based on their alleged contribution to climate change. The Supreme Court’s decision did not, however, address state law claims. This decision is expected to affect pending and future federal climate change cases. Although we are not currently a party to such litigation, we are monitoring these developments. 12

ItTABLE isOF not possible at this time to predict what new regulations may be promulgated to address greenhouse gas emissions or how the promulgation of any such regulations would impact our business. However, any new federal, regional or state restrictions on emissions of greenhouse gases imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on our business and the demand for the oil and natural gas we produce. CONTENTS

~~Legislation~~While oran ~~regulations~~oil ~~that~~pipeline, ~~may~~as bea ~~adopted~~general torule, ~~address~~must ~~climate~~use ~~change~~the ~~could~~indexing ~~also~~methodology ~~affect~~to ~~the~~change ~~markets~~its ~~for~~rates, ~~our~~FERC ~~products~~also byretained ~~making~~cost-of-service ~~our~~ratemaking, ~~products~~market-based ~~more~~rates, orand ~~less~~settlement ~~desirable~~rates ~~than~~as ~~competing~~alternatives ~~sources~~to ofthe ~~energy~~indexing approach. ToA ~~the~~pipeline ~~extent~~can ~~that~~follow ~~our~~a ~~products~~cost-of-service ~~are~~approach ~~competing~~when ~~with~~seeking ~~higher~~to ~~greenhouse~~increase ~~gas~~its ~~emitting~~rates ~~energy~~above ~~sources~~the ~~such~~rate asceiling ~~coal,~~(or ~~our~~when ~~products~~seeking ~~would~~to ~~become~~avoid ~~more~~lowering ~~desirable~~rates into the ~~market~~reduced ~~with~~rate ~~more~~ceiling), ~~stringent~~provided ~~limitations~~that onthe ~~greenhouse~~pipeline ~~gas~~can ~~emissions.~~establish ~~To the extent~~ that ~~our~~there ~~products~~is ~~are~~a ~~competing~~substantial ~~with~~divergence ~~lower~~between ~~greenhouse~~the ~~gas~~actual ~~emitting~~costs ~~energy~~experienced ~~sources~~by ~~such~~the aspipeline ~~solar~~ and ~~wind,~~the ~~our~~rate ~~products~~resulting ~~would~~from ~~become~~application ~~less~~of ~~desirable~~the inindex. ~~the~~A ~~market~~pipeline ~~with~~can ~~more~~charge ~~stringent~~market-based ~~limitations~~rates if onit ~~greenhouse~~establishes ~~gas~~that ~~emissions.~~it Welacks ~~cannot~~significant ~~predict~~market ~~with~~power ~~any~~in ~~certainty~~the ataffected ~~this~~markets. ~~time~~In ~~how~~addition, ~~these~~a ~~possibilities~~pipeline ~~may~~can ~~affect~~establish ~~our~~rates ~~operations~~under settlement.

~~Scientific~~Outer ~~studies~~Continental onShelf ~~climate~~Regulations. Our ~~change~~operations ~~suggest~~on ~~that~~federal ~~stronger~~oil ~~storms~~and ~~may~~gas ~~occur~~leases in the ~~future~~Gulf inof Mexico are subject to regulation by the ~~areas~~Bureau ~~where~~of weSafety ~~operate,~~and ~~although~~Environmental Enforcement (“BSEE”) and the ~~scientific~~Bureau ~~studies~~of ~~are~~Ocean ~~not~~Energy ~~unanimous~~Management (“BOEM”). ~~Due~~These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to ~~their~~various ~~location~~federal laws, ~~our~~including ~~operations~~the inOuter ~~the~~Continental ~~Gulf~~Shelf ofLands ~~Mexico~~Act (“OCSLA”). These laws and regulations are ~~vulnerable~~subject to ~~operational~~change, and ~~structural~~many ~~damages~~new ~~resulting~~requirements ~~from~~were ~~hurricanes~~imposed by the BSEE and ~~other~~BOEM subsequent ~~severe~~to ~~weather~~the ~~systems~~April ~~and~~2010 ~~our~~Deepwater ~~insurance~~Horizon ~~may~~incident. ~~not~~For ~~cover~~offshore ~~all~~operations, ~~associated~~lessees ~~losses~~must orobtain ~~may~~BOEM ~~become~~approval ~~more~~for ~~difficult~~exploration, ordevelopment ~~expensive~~and production plans prior to ~~secure~~the ifcommencement of such ~~storms~~operations. ~~occur~~In ~~with~~addition ~~increasing~~to ~~frequency~~permits required from other agencies such as the U.S. AsEnvironmental ~~discussed~~Protection ~~below~~Agency, in(the “~~Plugging~~EPA”), ~~Abandonment~~lessees ~~and~~must ~~Decommissioning,”~~obtain wea ~~are~~permit ~~taking~~from ~~steps~~the BSEE prior to ~~mitigate~~the ~~physical~~commencement ~~risks~~of ~~from~~drilling ~~storms~~and comply with regulations governing, ~~but~~among noother ~~assurance~~things, ~~can~~engineering beand ~~given~~construction ~~that~~specifications ~~future~~for ~~storms~~production ~~will~~facilities, ~~not~~safety ~~have~~procedures, aplugging ~~material~~and ~~adverse~~abandonment ~~effect~~of wells on ~~our~~the ~~business~~OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.

~~Naturally~~To ~~Occurring~~cover ~~Radioactive~~the ~~Materials~~various ~~(“NORM”).~~obligations ~~NORM~~of ~~are~~lessees ~~materials~~on ~~whose~~the ~~radioactivity~~OCS, issuch ~~enhanced~~as bythe ~~technological~~cost ~~processing~~to ~~such~~plug asand ~~mineral~~abandon ~~extraction~~wells orand ~~processing~~decommission ~~through~~and ~~exploration~~remove platforms and pipelines at the end of production, ~~conducted~~the byBOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the ~~oil~~BOEM ~~and~~exempts ~~natural~~the ~~gas~~lessee ~~industry~~from such financial assurance requirements. ~~NORM~~As ~~wastes~~a ~~are~~result ~~regulated~~of ~~under~~the bankruptcy of another Gulf of Mexico operator, the ~~RCRA~~BOEM ~~framework~~has indicated that it may review the estimated cost of future plugging, ~~but~~abandonment, ~~primary~~decommissioning ~~responsibility~~and removal obligations of other OCS operators, may evaluate any waivers or exemptions for ~~NORM~~such ~~regulation~~financial ~~has~~assurance ~~been~~obligations, aand ~~state~~may ~~function~~increase the amount of financial assurance required with respect to these obligations. ~~Standards~~In ~~have~~April ~~been~~2015, ~~developed~~we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for ~~worker~~waiver ~~protection;~~of ~~treatment~~certain supplemental bonding requirements for potential offshore decommissioning, ~~storage~~plugging and ~~disposal~~abandonment ofliabilities. ~~NORM~~The ~~waste;~~letters ~~management~~notified us that certain of ~~waste~~our ~~piles~~subsidiaries must provide approximately $566.5 million in supplemental financial assurance and/or bonding for their offshore oil and gas leases, ~~containers~~rights-of-way, and ~~tanks;~~rights-of-use and ~~limitations~~easements. ~~upon~~In June 2015, we reached agreements with the ~~release~~BOEM ofpursuant ~~NORM-contaminated~~to ~~land~~which ~~for~~we ~~unrestricted~~provided ~~use~~$54.7 Wemillion ~~believe~~of ~~that~~supplemental ~~our~~bonds ~~operations~~issued ~~are~~to inthe ~~material~~BOEM, ~~compliance~~and the BOEM agreed to withdraw its orders with ~~all~~regard ~~applicable~~to ~~NORM~~supplemental ~~standards~~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.

~~Offshore~~On ~~Leasing~~September ~~and~~22, ~~Permitting~~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. ~~Offshore~~Once ~~operations~~the Draft Guidance is finalized, ~~including~~the ~~engineering~~BOEM ~~and~~will ~~construction~~issue ~~specifications~~these ~~for~~supplemental ~~production~~bonding ~~facilities~~changes in a revised Notice to Lessees (“NTL”) in replacement of an existing NTL on supplemental bonding that was made effective on August 28, ~~safety~~2008. ~~procedures~~Among other things, ~~plugging~~the ~~and~~Draft ~~abandonment~~Guidance ofproposes ~~wells~~to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS projecting a relatively large net worth and ~~facility~~meeting ~~removals,~~certain ~~were~~other ~~formerly~~criteria ~~regulated~~have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations by ~~BOEMRE.~~self-insuring Onfor ~~October 1,~~those ~~2011~~liabilities, but only so long as the ~~U.S.~~cumulative ~~Department~~decommissioning ofliability amount being self-insured by the ~~Interior~~operator ~~completed~~is ~~its~~no ~~reorganization~~more than 50% of the ~~BOEMRE~~operator’s ~~(formerly~~net worth. Under the ~~Minerals~~Draft ~~Management~~Guidance, ~~Service)~~this bywaiver ~~the~~option ~~creation~~would be eliminated in favor of ~~three~~a ~~independent~~broadened ~~agencies~~self-insurance approach that would allow a larger array of operators on the OCS, ~~each~~not just those with ~~its~~relatively ~~own~~large ~~offshore~~net ~~oil~~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

15 13

~~and~~TABLE ~~gas~~OF responsibilities: the BOEM, with responsibility for leasing and environmental studies; the BSEE, with responsibility for field operations, including inspections, regulatory compliance, and oil spill response; and a third agency for management of revenues. The BOEMRE now ceases to exist. At this time, we believe that our operations are in material compliance with applicable regulations and orders. We cannot predict, however, the impact that the BOEMRE reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our operations. CONTENTS

~~Plugging~~Guidance, ~~Abandonment~~the ~~and~~BOEM ~~Decommissioning.~~proposes Weto ~~are~~establish ~~responsible~~a ~~for~~phased-in ~~plugging~~period ~~and~~for ~~abandoning~~establishing ~~wellbores~~compliance ~~and~~with ~~decommissioning~~supplemental ~~associated~~bonding ~~platforms~~obligations, ~~pipelines~~whereby ~~and~~operators ~~facilities~~may onseek ~~our~~payment ~~oil~~of ~~and~~estimated ~~natural~~costs ~~gas properties. Some~~ of ~~our~~decommissioning ~~offshore~~obligations ~~operations~~owed ~~are~~under ~~conducted~~a on“tailored ~~federal~~plan” ~~leases~~ that ~~are~~is ~~administered~~approved by the BOEM and ~~are~~requires ~~required~~payment toof ~~comply~~the ~~with~~supplemental ~~the~~bonding ~~regulations~~amount ~~and~~in ~~orders~~three ~~promulgated~~approximately equal installments of one-third each, by no later than approximately 120, 240 and 360 calendar days, respectively, from the date of BOEM ~~and~~approval ~~BSEE~~of ~~under~~the ~~OCSLA~~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 ~~are~~currently ~~subject~~maintain approximately $58.3 million in lease and/or area bonds issued to anthe ~~active~~BOEM ~~NTL,~~and ~~effective~~approximately ~~October 15,~~$122.5 ~~2010,~~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 ~~platforms~~facilities. ~~The~~Thus, ~~NTL~~our ~~imposes~~total ~~more~~supplemental ~~stringent~~bonding ~~requirements~~is ~~for~~approximately ~~decommissioning~~$180.8 ~~facilities~~million, ~~that~~with ~~pose~~an aannual ~~hazard~~premium toexpense ~~safety~~of or$2.7 ~~the~~million. ~~environment~~In addition, assince ~~well~~June as2015, ~~for~~we ~~facilities~~have ~~that~~received ~~are~~additional ~~not~~letters ~~useful~~from the BOEM in which the BOEM requests additional supplemental bonding for ~~lease~~other ~~operations~~certain ~~and~~properties ~~that~~previously ~~are~~exempt ~~not~~from ~~capable~~supplemental bonding, generally as a result of ~~oil~~exempt ~~and~~co-owners ~~natural~~either ~~gas~~losing ~~production~~their exemptions or no longer owning an interest in ~~“paying~~the ~~quantities~~property.” ~~Historically~~Furthermore, ~~approval~~we ~~was~~anticipate ~~granted~~our tosupplemental ~~operators~~bonding requirements to ~~maintain~~increase ~~these~~as ~~structures~~we infurther ~~order~~develop or acquire additional properties subject to ~~conduct~~the ~~future~~BOEM’s ~~activities~~financial assurance requirements. ~~However,~~Although ~~the~~we ~~NTL~~believe ~~significantly~~we ~~restricts~~are ~~this~~currently ~~practice.~~in ~~Under~~compliance with the ~~NTL~~supplemental bonding requirements, ~~lessees~~the ~~must~~BOEM ~~submit~~may anin ~~application~~the future continue to ~~permanently~~review ~~plug~~our ~~any~~plugging, ~~well~~abandonment, ~~that~~decommissioning ~~poses~~and aremoval ~~hazard~~obligations; re-evaluate the adequacy of our financial assurances; and require us to ~~safety~~provide additional supplemental bonding or ~~the~~other ~~environment~~surety ~~within~~for 30most ~~days~~or ~~after~~all ~~identifying~~of ~~the~~our ~~hazard~~properties. ~~The~~Furthermore, ~~NTL~~in ~~also~~addition ~~imposes~~to ~~new~~the ~~deadlines~~Draft ~~for~~Guidance ~~removing~~describing ~~platforms~~revised orsupplemental ~~other~~bonding ~~facilities~~procedures that ~~are~~may nobe ~~longer~~used ~~useful~~by the BOEM, the BOEM is actively seeking to adjust its financial assurance requirements mandated by rule for ~~operations~~all companies operating in federal waters. ~~Furthermore~~In August 2014, the ~~NTL~~BOEM ~~imposes~~issued ~~new~~an ~~deadlines~~Advanced ~~for~~Notice ~~plugging,~~of ~~abandoning~~Proposed orRulemaking ~~performing~~(“ANPR”) ~~downhole~~in ~~zonal~~which ~~isolation~~the onagency ~~wells~~indicated that ~~are~~it nowas ~~longer~~considering ~~useful~~bolstering ~~for~~the ~~operations~~financial ~~and~~assurance ~~that~~requirements ~~are~~currently nomandated ~~longer~~by ~~capable~~rule. The cost of ~~production~~compliance inwith ~~paying~~our ~~quantities.~~existing Insupplemental ~~May~~bonding ~~2013,~~requirements weor ~~responded~~any other changes to athe ~~written~~BOEM’s ~~request~~current ~~from~~bonding ~~BOEM~~requirements ~~for~~or ~~information~~regulations onapplicable to us or our ~~“idle~~properties ~~iron”~~could ~~issues~~be bysubstantial ~~submitting~~and acould ~~company-wide~~materially ~~three-year~~and ~~plan~~adversely ~~for~~affect our ~~wellbore~~financial ~~plugging~~condition, cash flows, and ~~abandonment~~results of operations. Please read “Risk Factors — We and ~~decommissioning~~our ~~activities~~subsidiaries ~~through~~have ~~2016~~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. ”

~~The~~Under ~~effects~~certain ofcircumstances, ~~Hurricanes Katrina and Rita during~~ the ~~2005~~BSEE ~~hurricane~~may ~~season~~require ~~and~~our ~~Hurricanes Ike and Gustav in 2008 significantly impacted oil and gas~~ operations on ~~the~~federal ~~OCS.~~leases ~~The effects included structural damage~~ to ~~fixed~~be ~~production~~suspended ~~facilities,~~or ~~semi-submersibles and jack-up drilling rigs~~terminated. ~~Both~~Any ~~the~~such ~~BOEM~~suspension ~~and~~or ~~the~~termination ~~BSEE~~could ~~are~~materially ~~concerned about the potential for catastrophic damage to key infrastructure~~ and ~~the~~adversely ~~resultant~~affect ~~pollution~~our ~~from~~financial ~~future~~condition storms. In an effort to reduce the potential for future damage, the former BOEMRE issued still active guidance through NTLs, aimed at improving platform survivability by taking into account environmental and ~~oceanic conditions in the design of platforms and related structures~~operations. ItWe isown ~~possible~~certain ~~that~~crude ~~similar,~~oil ifpipelines ~~not~~located ~~more~~on ~~stringent, design and operational requirements will be issued by~~ the ~~BOEM or BSEE in the future and these new requirements could increase our operating costs~~OCS. ~~The BOEM,~~ BSEE ~~and~~regulates ~~other~~terms ~~regulatory bodies, including those regulating the decommissioning~~ of ~~our~~service pipelines and facilities under the jurisdiction of the state of Louisiana, may change their requirements or enforce requirements in a manner inconsistent with our expectations, which could materially increase the cost of such activities and/or accelerate the timing of cash expenditures and could have a material adverse effect on ~~our~~OCS ~~financial~~pipelines ~~position,~~to ~~results~~provide ofopen ~~operations~~ and ~~cash~~nondiscriminatory ~~flows~~access.

~~The~~Gathering ~~failure~~regulations. Section to1(b) ~~comply~~of ~~with~~the ~~these~~federal ~~rules~~Natural ~~and~~Gas ~~regulations~~Act ~~could~~(“NGA”) ~~result~~exempts innatural ~~substantial~~gas ~~penalties,~~gathering ~~including~~facilities ~~lease~~from ~~termination in~~ the ~~case~~jurisdiction of ~~federal~~FERC ~~leases~~under the NGA. ~~Under~~Although ~~limited~~FERC ~~circumstances,~~has ~~the~~not ~~BSEE~~made ~~could~~any ~~require~~formal usdeterminations with respect to ~~suspend~~any orof ~~terminate~~the ~~our~~natural ~~operations~~gas ongathering apipeline ~~federal~~facilities ~~lease~~that orwe own, we ~~could~~believe ~~have~~that ~~difficulty~~our ~~entering~~natural ~~into~~gas ~~new~~gathering ~~leases~~pipelines inmeet the ~~future~~traditional tests that FERC has used to establish a pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. The ~~regulatory~~distinction ~~burden~~between onFERC-regulated ~~the~~transmission ~~oil~~facilities and ~~natural~~federally ~~gas~~unregulated ~~industry~~gathering ~~increases~~facilities, however, ~~our~~has ~~cost~~been the subject of ~~doing~~substantial ~~business~~litigation and, ~~consequently~~over time, ~~affects~~FERC’s ~~our~~policy ~~profitability~~for determining which facilities it regulates has changed. ~~Our~~In ~~competitors~~addition, inthe distinction between FERC-regulated transmission facilities, on the ~~oil~~one hand, and ~~natural~~gathering ~~gas~~facilities, ~~industry~~on ~~are~~the ~~subject~~other, tois ~~the~~a ~~same~~fact-based ~~regulatory~~determination ~~requirements~~made ~~and~~by ~~restrictions~~FERC ~~that~~on ~~affect~~a ~~our~~case-by-case ~~operations,~~basis. ~~although~~The ~~the~~classification ~~impact~~and regulation of ~~those~~our ~~requirements~~gathering lines may ~~vary~~be ~~significantly~~subject to change based on ~~the~~future ~~nature~~determinations ~~and~~by ~~location~~FERC, ofthe ~~operations~~courts ~~and~~or ~~related~~the ~~pipelines~~U.S. ~~and facilities~~Congress.

~~Significant~~State ~~Customers~~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

We market substantially all of our oil and natural gas production. We sell our natural gas to marketing companies pursuant to a variety of contractual arrangements, generally under contracts with terms no longer than six to twelve months. Pricing on those contracts is based largely on published regional index pricing. We sell our oil under contracts with month-to-month terms to a variety of purchasers. The pricing for oil is based upon the posted prices set by major purchasers in the production area, reporting publications, or upon New York Mercantile Exchange (“NYMEX”) pricing. Oil pricing is adjusted for quality and transportation differentials. Oil and natural gas purchasers are selected on the basis of price, credit quality and service reliability. 14

~~Our~~TABLE ~~oil,~~OF condensate and natural gas production is sold to a variety of purchasers, historically at market-based prices. We believe that the prices for liquids and natural gas are comparable to market prices in the areas where we have production. Of our total oil and natural gas revenues in 2013, Chevron USA, Inc. accounted for approximately 63%, ConocoPhillips accounted for approximately 24%, and Shell Trading (US) Company accounted for approximately 6%. Due to the nature of the markets for oil and natural gas, we do not believe that the loss of any one of these customers would have a material adverse effect on our financial condition or results of operations, although a temporary disruption in production revenues could occur. CONTENTS

16 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.

EmployeesEnvironmental Regulations

AsVarious federal, state and local laws and regulations relating to the protection of ~~December 31,~~the ~~2013~~environment, weincluding ~~had~~the ~~188 full-time~~discharge ~~employees~~of materials into the environment, ~~including~~may 39affect ~~geoscientists~~our exploration, ~~engineers~~development and ~~technicians~~production operations and 94the ~~field~~costs ~~personnel~~of those operations. ~~Our~~These ~~employees~~laws ~~are~~and ~~not~~regulations, ~~represented~~among byother ~~any~~things, ~~labor~~govern ~~union~~the oramounts ~~other~~and ~~collective~~types ~~bargaining~~of ~~organization.~~substances Wethat ~~consider~~may ~~relations~~be ~~with~~released ~~our~~into ~~employees~~the environment, the issuance of permits to beconduct ~~satisfactory~~exploration, drilling and weproduction ~~have~~operations, ~~never~~the ~~experienced~~handling, adischarge ~~work~~and ~~stoppage~~disposition orof ~~strike.~~waste Wematerials, ~~regularly~~the ~~use~~reclamation ~~independent~~and ~~consultants~~abandonment of wells, sites and ~~contractors~~facilities, tothe ~~perform~~establishment ~~various~~of ~~professional~~financial assurance ~~services~~requirements infor ~~various~~oil ~~areas,~~spill ~~including~~response ~~in our~~costs ~~exploration~~and the decommissioning of offshore facilities and ~~development~~the ~~operations,~~remediation ~~production~~of contaminated sites. These laws and regulations may impose liabilities for noncompliance and contamination resulting from our operations and ~~certain~~may ~~administrative~~require ~~functions~~suspension or cessation of operations in affected areas.

~~Competitors~~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:

~~Our~~• ~~competitors~~Clean ~~include~~Air numerous independent oil and gas companies and major oil companies. Many of our larger competitors possess and employ financial and personnel resources substantially greater than ours. These competitors are able to pay more for productive oil and natural gas properties and exploratory prospects and to defineAct, ~~evaluate,~~which ~~bid~~governs ~~for~~air and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to replace and expand our reserve base depends on our ability to attract and retain qualified personnel and identify and acquire suitable producing properties and prospects for future drilling. See Part I, Item 1A, “Risk Factors,” for additional information about risks related to our competitors, personnel and ability to acquire producing properties and prospects. emissions;

~~Seasonality~~• Clean Water Act, which governs discharges of pollutants into waters of the United States;

~~Historically,~~• ~~the~~Comprehensive ~~demand~~Environmental ~~for~~Response, ~~and~~Compensation ~~price of natural gas generally trends upward during the winter months~~ and ~~downward~~Liability ~~during the summer months. However~~Act, ~~these~~which ~~seasonal~~imposes ~~fluctuations~~strict ~~can~~liability ~~be interrupted due to summer storage practices~~ where ~~pipeline~~releases ~~companies, utilities, distribution companies and industrial users may purchase and place into storage facilities a portion~~ of ~~their~~hazardous ~~anticipated~~substances ~~winter~~have ~~requirements~~occurred ofor ~~natural gas. These trends~~ are ~~also~~threatened disrupted by extreme market impacts such as those that occurred in 2008, when oil and natural gas prices reached peak levels in the summer months, then fell during the winter. Tropical storms and hurricanes generally occur in the Gulf of Mexico during late summer and fall, which may require us to ~~evacuate personnel and shut-in production during those periods. The winds and turbulent current conditions that~~ occur in(commonly ~~the~~known ~~winter~~as months can impact our ability to safely load, unload and transport personnel and equipment, and perform operations, including plugging, abandonment and other decommissioning activities, which can delay our operations, increase the cost of our operations and/or delay the restoration and maintenance of our oil and natural gas production. “Superfund”);

~~Cautionary~~• ~~Statement~~Resource ~~Concerning~~Conservation ~~Forward~~and ~~Looking~~Recovery ~~Statements~~Act, which governs the management of solid waste;

~~This~~• ~~Annual~~Endangered ~~Report~~Species ~~contains~~Act, ~~forward-looking~~Marine ~~statements~~Mammal ~~within~~Protection ~~the meaning of~~Act, and weMigratory ~~intend~~Bird ~~that~~Treaty ~~such~~Act, ~~forward-looking~~which ~~statements~~govern ~~be subject to~~ the ~~safe~~protection ~~harbor provisions~~ of, ~~the U.S. federal securities laws. Forward-looking statements are~~animals, byflora ~~definition, statements that are generally not historical in nature~~ and relate to possible future events. They may be, but are not necessarily, identified by words such as “will,” “would,” “should,” “likely,” “estimates,” “thinks,” “strives,” “may,” “anticipates,” “expects,” “believes,” “intends,” “goals,” “plans,” or “projects” and similar expressions. fauna;

~~These~~• ~~forward-looking~~Oil ~~statements~~Pollution ~~reflect~~Act our current views with respect to possible future events, are based on various assumptions and are subject to risks and uncertainties. These forward-looking statements are not guarantees or predictions of ~~our future performance~~1990, ~~and~~which ~~our~~imposes ~~actual~~liabilities ~~results~~resulting ~~and future developments may differ materially~~ from ~~those~~discharges ~~projected~~of ~~in,~~oil ~~and~~into ~~contemplated~~navigable ~~by,~~waters ~~the~~of forward-looking statements. As a result, you should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements. Among the ~~factors~~United ~~that could cause actual results to differ materially are the risks and uncertainties described under Part I, Item 1A, “Risk Factors,” including the following:~~ States;

•~~planned~~ Emergency Planning and ~~unplanned~~Community ~~capital~~Right-to-Know ~~expenditures;~~Act, which requires reporting of toxic chemical inventories;

•~~adequacy~~ ofSafe ~~capital~~Drinking ~~resources~~Water ~~and liquidity including~~Act, ~~but~~which ~~not~~governs ~~limited~~underground ~~to,~~injection ~~access~~and todisposal ~~additional capacity under our Senior Credit Facility~~activities; and

•~~volatility~~ inU.S. ~~oil~~Department ~~and~~of ~~natural~~Interior ~~gas~~regulations, ~~prices;~~which impose liability for pollution cleanup and damages.

~~•volatility~~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 ~~financial~~reimbursement to us of costs incurred for the containment and ~~credit~~clean-up ~~markets;~~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.

~~•changes~~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 ~~general~~which ~~economic~~an ~~conditions;~~offshore facility is located. The OPA assigns joint and several, strict liability, without regard to fault, to each

~~•uncertainties in reserve and production estimates;~~ 15

~~•replacing~~TABLE ~~our~~OF ~~oil and natural gas reserves;~~ CONTENTS

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 ~~•unanticipated~~facilities ~~recovery~~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 ~~production~~whether ~~problems;~~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.

~~•availability~~Climate Change. The U.S. Environmental Protection Agency (the “EPA”) has determined that emissions of carbon dioxide, ~~cost~~methane and ~~adequacy~~other “greenhouse gases” present an endangerment to public health and the environment because emissions of ~~insurance~~such ~~coverage;~~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.

~~•hurricane~~In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and ~~other~~almost ~~weather~~one-~~related~~half ~~interference~~of ~~with~~the ~~business~~states ~~operations;~~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.

~~•drilling~~The ~~and~~adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating ~~risks;~~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.

•productionDerivative expense estimates; Activities

17 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.

~~•the impact of derivative positions;~~ 16

~~•our~~TABLE ~~ability~~OF ~~to retain and motivate key executives and other necessary personnel;~~ CONTENTS

•availabilityMarketing of drilling and productionSignificant equipment and field service providers; Customers

~~•the~~We ~~effects~~market substantially all of ~~delays~~our inoil ~~completion~~and ~~of,~~natural orgas ~~shut-ins~~production from the properties we operate. We also market more than half of, our oil and natural gas ~~gathering~~production ~~systems,~~from ~~pipelines~~the fields we do not operate. The majority of our operated oil and ~~processing~~gas ~~facilities;~~production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.

~~•potential~~Of ~~costs~~our ~~associated~~total ~~with~~oil ~~complying~~and ~~with~~natural ~~new~~gas orrevenues ~~modified~~for ~~regulations~~the oryear ~~interpretations~~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 ~~such~~other ~~regulations~~customers, ~~promulgated~~and bywe ~~the~~believe ~~BOEM~~that those customers, ~~the~~along ~~BSEE~~with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the ~~PHMSA;~~ event that Chevron, ConocoPhillips or Shell curtailed their purchases.

~~•the~~We ~~impact~~transport a portion of ~~political~~our oil and ~~regulatory~~natural ~~developments;~~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.

•risks and liabilities associated with acquired properties or businesses; Employees

~~•our~~Effective ~~ability~~January to1, ~~make~~2015, ~~and~~all ~~integrate~~remaining ~~acquisitions;~~ EPL employees became employees of Energy XXI Services, LLC, an affiliated party.

~~•our substantial level of indebtedness;~~ 17

~~•our~~TABLE ~~ability~~OF ~~to incur additional indebtedness;~~ CONTENTS

~~•oil~~Item ~~and~~1A. ~~gas~~Risk ~~prices and competition;~~ Factors

"Oil cyberand attacks;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 ~~ability~~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 ~~generate~~June ~~sufficient~~30, ~~cash~~2015 ~~flow~~ranged from a high of $105.34 to ~~meet~~a ~~our~~low ~~debt~~of ~~service~~$43.46, a decrease of 58.7%, and ~~other~~the ~~obligations~~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:

~~Many~~• ofdomestic ~~these factors are beyond our ability to control or predict. Any, or a combination, of these factors could materially affect our future financial condition or results of operations~~ and ~~the~~foreign ~~ultimate~~supplies ~~accuracy~~ of ~~the~~oil ~~forward-looking statements. These forward-looking statements are not guarantees of our future performance,~~ and ~~our~~natural actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements. gas;

~~For~~• aprice ~~further list~~ and ~~description~~quantity of ~~various~~foreign ~~risks,~~imports relevant factors and uncertainties that could cause future results or events to differ materially from those expressed or implied in our forward-looking statements, see “Risk Factors” in Part 1, Item 1A of ~~this~~oil ~~Annual Report~~ and ~~elsewhere~~natural in this Annual Report, our reports and registration statements filed from time to time with the SEC, and other announcements we make from time to time. Given these risks and uncertainties, you should not place undue reliance on these forward-looking statements. gas;

~~Although~~• weactions ~~believe~~of ~~that~~ the ~~assumptions~~Organization onof ~~which~~Petroleum ~~any~~Exporting ~~forward-looking~~Countries ~~statements are based in this Annual Report~~ and other ~~periodic reports filed by us are reasonable when and as made, no assurance can be given that such assumptions will prove correct. All forward~~state-~~looking~~controlled ~~statements~~oil incompanies ~~this~~relating ~~Annual~~to ~~Report~~oil ~~are expressly qualified in their entirety by the cautionary statements in this section~~ and ~~elsewhere~~natural ingas ~~this~~price ~~Annual Report~~ and weproduction ~~undertake no obligation to publicly update or revise any forward-looking statements, except as required by applicable securities laws and regulations.~~ controls;

~~Item 1A.Risk~~• ~~Factors~~level of consumer product demand, including as a result of competition from alternative energy sources;

~~Risks~~• ~~Related~~level toof ~~Our~~global ~~Business~~oil and natural gas exploration and production activity;

~~Our~~• ~~business~~domestic ~~requires substantial capital investment~~ and ~~maintenance~~foreign ~~expenditures,~~governmental ~~and our capital resources may not be adequate to provide for all of our cash requirements.~~ regulations;

~~Our~~• ~~operations~~level ~~are~~of ~~capital~~global ~~intensive. Our ability to replace our~~ oil and natural gas production and maintain our production levels and reserves requires extensive capital investment, including substantial capital expenditures for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our business also requires substantial expenditures for routine maintenance. Our capital requirements will depend on numerous factors, and we cannot predict accurately the timing and amount of our capital requirements. Though we have the ability to borrow under our Senior Credit Facility, we intend to finance our development and exploration capital expenditures with cash flow from operations. Because our cash flows are subject to a range of economic, competitive and business risks, we may not be able to generate sufficient cash flow from operations to meet our debt payment obligations and to fund these capital requirements. Additionally, the amounts available to us under our Senior Credit Facility may not be sufficient for our capital requirements not funded by cash flow from operations, and we may not be able to access additional financing resources for a variety of reasons, including restrictive covenants in our Senior Credit Facility and the indenture governing our senior notes. If we are unable to make scheduled payments on our Senior Credit Facility, or if our financing requirements are not met by our Senior Credit Facility and we are unable to access sources of additional financing on terms we find acceptable, our business, operations, financial condition and cash flows will be negatively impacted. inventories;

~~Without~~• ~~additional~~political ~~capital~~conditions ~~resources,~~in ~~we may be forced to limit~~ or ~~defer~~affecting ~~our~~other ~~planned~~ oil-producing and natural gas-producing ~~exploration~~countries, ~~and~~including ~~development~~the ~~program~~current ~~and~~conflicts ~~this~~in ~~will adversely affect~~ the ~~recoverability~~Middle ~~and~~East ~~ultimate value of our oil~~ and ~~natural~~conditions ~~gas properties,~~ in ~~turn~~South ~~negatively~~America ~~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 complete potential acquisitions, Russia;

18 • weather conditions;

~~obtain~~• ~~credit~~technological ~~necessary~~advances toaffecting ~~enter into derivative contracts to hedge our future crude~~ oil and natural gas production orand ~~to capitalize on other business opportunities.~~ consumption;

~~The~~• ~~borrowing~~overall ~~base~~U.S. ~~under our Senior Credit Facility is subject to re-determination~~ and ~~could~~global beeconomic ~~reduced~~conditions; ~~in the future if commodity prices decline, which will limit our available funding for exploration~~ and ~~development.~~

~~Our~~• ~~current~~price borrowing base under our Senior Credit Facility is $475 million. As of February 21, 2014, we had $210 million outstanding under our Senior Credit Facility. Our borrowing base is subject to semi-annual and ~~certain~~availability ~~other interim re-determinations by our lenders in their sole discretion, based on the collateral value~~ of ~~our~~alternative ~~proved reserves~~fuels. ~~Any reduction of the borrowing base is subject to approval of lenders holding not less than 66 2/3% of the lending commitments under our Senior Credit Facility.~~

InOur ~~the~~financial ~~future~~condition, werevenues, ~~may~~profitability ~~not~~and bethe ~~able~~carrying tovalue ~~access~~of ~~adequate~~our ~~funding~~properties ~~under~~depend ~~our~~upon ~~Senior~~the ~~Credit~~prevailing ~~Facility~~prices asand ademand ~~result~~for ofoil ~~(i) a~~and ~~decrease~~natural ingas. ~~our~~The ~~borrowing~~speed ~~base~~and ~~due~~severity toof the ~~outcome~~decline ofin aoil ~~subsequent~~prices ~~borrowing~~during ~~base~~our ~~re-determination,~~2015 orfiscal ~~(ii) an~~year ~~unwillingness~~and orthe ~~inability~~continued onlower prices in the ~~part~~first quarter of our ~~lending~~fiscal ~~counterparties~~year to2016 ~~meet~~has ~~their~~materially ~~funding~~affected ~~obligations.~~our Ifresults ~~oil~~of oroperations ~~natural~~and ~~gas~~our ~~commodity~~estimates ~~prices~~of ~~deteriorate,~~ our ~~revised~~proved ~~borrowing~~oil ~~base~~and ~~under~~natural ~~our~~gas ~~Senior~~reserves. ~~Credit~~Any ~~Facility~~sustained ~~could~~periods beof ~~reduced.~~low Asprices afor ~~result,~~oil weor ~~may~~natural begas ~~unable~~are likely to ~~obtain~~materially ~~adequate~~and ~~funding~~adversely ~~under~~affect our ~~Senior~~financial ~~Credit~~position, ~~Facility.~~the Ifquantities ~~funding~~of isnatural ~~not~~gas ~~available~~and ~~when~~oil ~~needed,~~reserves itthat ~~could~~we ~~adversely~~can ~~affect~~economically produce, our ~~exploration~~cash ~~and~~flow ~~development~~available ~~plans~~for ascapital ~~currently~~expenditures ~~anticipated~~ and our ability to ~~make~~access ~~new~~funds ~~acquisitions,~~from ~~each~~EGC ofand ~~which~~EGC’s ~~could~~ability ~~have~~to aaccess ~~material~~funds ~~adverse~~under ~~effect on~~ our ~~production,~~revolving ~~revenues~~credit facility and ~~results~~through ofthe ~~operations~~capital markets.

InWe addition,may ifnot therebe isable ato decreasegenerate insufficient ourcash borrowingflows baseto asservice aall result of theour outcomeindebtedness of a subsequent borrowing base re-determination and, asmay a result of such decrease, the outstanding borrowings under our Senior Credit Facility exceed the re-determined borrowing base, we will be requiredforced to repaytake half of such difference within 45 days and the other halfactions of such difference within 90 days. We may not have the financial resources in theorder future to makesatisfy anyour mandatoryobligations principal prepayments required under our Senior Credit Facilityindebtedness, which wouldmay resultnot inbe an event of default under the Senior Credit Facilitysuccessful.

~~Our~~As ~~substantial~~of ~~level~~June of30, 2015, we had total indebtedness ~~could~~of ~~adversely~~$1,018 ~~affect~~million. Based on our ~~financial~~current ~~condition~~debt ~~and~~balance, ~~prevent~~we usexpect ~~from~~to ~~fulfilling~~have substantial interest payments due during fiscal year 2016, totaling $80.1 million. In addition, our ~~obligations~~$510 ~~under~~million ~~the~~aggregate ~~notes~~principal amount 8. 25% Senior Notes are due February 15, 2018.

WeIn ~~and~~addition, ~~the~~our ~~guarantors~~revolving ofcredit ~~the~~facility ~~8.25%~~is ~~senior~~scheduled ~~notes~~to ~~due~~mature ~~2018~~on ~~(the~~April ~~“8.25% Senior Notes”)~~9, on2018; ~~a consolidated basis at December 31~~however, ~~2013,~~the ~~had~~maturity ~~outstanding $640 million~~ of ~~senior~~our ~~indebtedness,~~revolving ~~including~~credit ~~$130~~facility ~~million~~will ofaccelerate ~~secured~~if ~~debt~~EGC’s ~~under~~9.25% ~~our~~ Senior ~~Credit~~Notes ~~Facility.~~are ~~Our~~not ~~substantial~~retired ~~level~~or ofrefinanced ~~indebtedness~~by ~~could~~May ~~have~~15, ~~significant~~2017 ~~effects~~or on our ~~business~~8.25% ~~For~~Senior ~~example,~~Notes ~~our~~are ~~level~~not ofretired ~~indebtedness~~or ~~and~~refinanced ~~the~~by ~~terms~~July of15, ~~our~~2017. ~~debt agreements may:~~

~~•make~~Our itability ~~more~~to ~~difficult~~make ~~for~~scheduled uspayments on, or to ~~satisfy~~refinance, our ~~financial~~debt obligations ~~under~~will ~~the~~depend ~~8.25%~~on ~~Senior Notes,~~ our ~~other~~financial ~~indebtedness~~ and ~~our~~operating ~~contractual~~performance, ~~and~~which ~~commercial~~is ~~commitments~~subject ~~and~~to ~~increase~~prevailing ~~the~~economic ~~risk~~and ~~that~~competitive weconditions ~~may~~and ~~default on our debt obligations;~~

~~•heighten our vulnerability to downturns in our business, our industry or in the general economy and restrict us from exploiting business opportunities or making acquisitions;~~ 18

~~•limit~~TABLE ~~management’s~~OF ~~discretion in operating our business;~~ CONTENTS

~~•require~~certain usfinancial, tobusiness ~~dedicate~~and aother ~~substantial~~factors ~~portion~~beyond ofour control. We cannot assure you that our business will generate sufficient cash ~~flow~~flows from ~~operations~~operating activities or that future sources of capital will be available to ~~payments~~us onin 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, ~~thereby~~there ~~reducing~~can be no assurance that we will have the ~~availability~~ability ofto 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 ~~fund~~service ~~working~~our ~~capital,~~debt ~~capital~~or ~~expenditures,~~meet ~~and~~our ~~other~~debt obligations ~~general~~as ~~corporate~~they ~~purposes;~~become due, we may be required to:

•~~place~~ usrestructure ator arefinance ~~competitive~~all ~~disadvantage~~or ~~compared~~a toportion of our ~~competitors that have less~~ debt;

•~~limit~~ ~~our~~obtain ~~ability to borrow~~ additional ~~funds~~financing; ~~and~~

•~~limit~~ ~~our~~sell ~~flexibility~~some inof ~~planning for, or reacting to, changes in~~ our ~~business,~~assets ~~the industry in which we operate~~ or ~~the~~operations; ~~general economy.~~ or

~~Each~~• ofreduce ~~these~~or ~~factors~~delay ~~may~~capital have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to the 8.25% Senior Notes and to satisfy our other debt obligations will depend on our future operating performanceexpenditures, ~~which~~including ~~will~~development ~~be affected by prevailing economic conditions~~ and ~~financial,~~exploration ~~business and other factors affecting our company and industry, many of which are beyond our control~~efforts. In addition, the indenture governing the 8.25% Senior Notes (the “2011 Indenture”) and our Senior Credit Facility contain financial and other restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our debts.

~~Despite~~EGC and EPL may be unable to restructure or refinance our ~~substantial~~debt, ~~level~~obtain ofadditional ~~indebtedness~~financing weor ~~may~~capital ~~still~~or besell ~~able~~assets toon ~~incur~~satisfactory ~~substantially~~terms, ~~more~~if ~~indebtedness~~at all. If we cannot make scheduled payments on our debt, ~~which~~we ~~would~~will ~~increase~~be in default under the ~~risks~~terms ~~associated~~of ~~with~~the agreements governing our ~~leverage.~~ debt and, as a result:

~~Even~~• ~~with~~ our ~~existing~~ debt ~~levels,~~holders wecould ~~and~~declare ~~our~~all ~~subsidiaries~~outstanding ~~may~~principal beand ~~able~~interest to ~~incur~~be ~~substantial~~due ~~amounts~~and ofpayable, ~~additional~~which ~~debt~~would in ~~the~~turn ~~future,~~trigger ~~including~~cross-acceleration ~~debt~~or ~~under~~cross-default ~~our~~rights ~~existing~~between ~~and~~the ~~future~~relevant ~~credit~~agreements ~~facilities.~~and Asthe holders of ~~December 31,~~EGC’s ~~2013,~~11.0% weNotes ~~had~~due ~~total~~March ~~debt~~15, ~~outstanding~~2020 ofcould ~~$640~~foreclose ~~million~~against ~~consisting of $510 million of~~ the ~~8.25%~~assets ~~Senior~~securing ~~Notes~~their ~~and $130 million of outstanding~~ notes;

19 • the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and

~~borrowings~~• under our Senior Credit Facility. In January 2014, our lenders approved a $50 million increase in our borrowing base under the facility, increasing our borrowing base to $475 million. As of February 21, 2014, we ~~had~~could ~~$210.0~~be ~~million~~forced ~~outstanding~~into ~~and~~bankruptcy $265 million in availability under our Senior Credit Facility. Although the terms of the 8.25% Senior Notes and our current and future credit facilities will limit our ability to incur additional debt, these terms do not and will not prohibit us from incurring substantial amounts of additional debt for specific purposes or ~~under certain circumstances~~liquidation. If new debt is added to our and our subsidiaries’ current debt levels, the related risks that we and they now face could intensify and could further exacerbate the risks associated with our leverage.

Our Seniorsignificant Creditlevel Facilityof andindebtedness themay 2011limit Indentureour imposeability significantto operatingborrow andadditional financialfunds restrictionsor capitalize on usacquisition or other business opportunities. In addition, the covenants in the indentures governing our senior notes and our subsidiariesrevolving credit facility impose restrictions that may preventlimit usour fromability pursuingto take certain businessactions. opportunitiesOur andfailure restrictto ourcomply abilitywith tothese operatecovenants could result in the acceleration of our businessoutstanding indebtedness.

~~Our~~As ~~Senior~~of ~~Credit~~June ~~Facility~~30, 2015, we had total indebtedness of $1,018 million. Our leverage and the ~~2011~~current ~~Indenture~~and ~~contain~~future ~~covenants~~restrictions ~~that~~contained ~~restrict~~in the agreements governing our ~~and~~indebtedness may reduce our ~~restricted~~ability ~~subsidiaries’~~to orincur additional indebtedness, engage in ~~the~~certain ~~case~~transactions ofor ~~the~~capitalize ~~Senior~~on ~~Credit~~acquisition ~~Facility,~~or ~~our~~other business opportunities. Our indebtedness and ~~all~~other offinancial ~~our~~obligations ~~subsidiaries’,~~and ~~ability~~restrictions tocould ~~take~~have ~~various~~financial ~~actions~~consequences. For example, ~~such~~they ascould:

•~~transferring~~ impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or ~~selling~~other ~~assets~~purposes;

•~~paying~~ ~~dividends~~increase orour ~~distributions,~~vulnerability ~~buying~~to ~~subordinated~~general ~~indebtedness~~adverse oreconomic ~~securities,~~and ~~making~~industry ~~certain investments or making other restricted payments~~conditions;

•~~incurring~~ orresult ~~guaranteeing~~in ~~additional~~higher ~~indebtedness~~interest ~~or,~~expense in the ~~case~~event of ~~the~~increases ~~2011~~in ~~Indenture~~interest ~~and~~rates ~~only~~since ~~with~~some ~~respect~~of to our ~~restricted~~debt ~~subsidiaries,~~is ~~issuing~~at ~~preferred~~variable ~~stock;~~rates of interest;

•~~creating~~ orrequire ~~incurring~~us ~~liens;~~to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements;

•~~incurring~~ ~~dividend~~limit our flexibility in planning for, or ~~other~~reacting ~~payment~~to, ~~restrictions~~changes ~~affecting~~in ~~restricted~~our ~~subsidiaries~~business and industry; and

•~~consummating~~ aplace ~~merger,~~us ~~consolidation~~at ora ~~sale~~competitive ofdisadvantage ~~all~~to orthose ~~substantially~~who ~~all~~have ~~our~~proportionately ~~assets;~~less debt.

~~•entering~~In ~~into~~addition, ~~transactions~~our ~~with~~revolving ~~affiliates;~~credit facility contains and our indentures governing our unsecured notes contain covenants that restrict our ability to take various actions, such as:

• engaging in ~~business~~businesses other than ~~a business that is~~ the ~~same~~oil orand ~~similar~~gas ~~to our current~~ business ~~or a reasonably related extension thereof~~;

•~~making~~ ~~capital~~incurring ~~expenditures~~or ~~other~~guaranteeing ~~than~~additional ~~those~~indebtedness ~~related~~or toissuing ~~our~~disqualified ~~business~~capital ~~as a domestic exploration and production company~~stock;

~~•issuing capital stock of certain subsidiaries;~~ 19

~~•entering~~TABLE ~~into~~OF ~~sale/leaseback transactions;~~ CONTENTS

• making ~~acquisitions or~~ investments; ~~and~~

•~~designating~~ ~~subsidiaries~~paying asdividends, ~~unrestricted~~redeeming ~~subsidiaries.~~certain indebtedness or making other restricted payments;

In• ~~addition, our Senior Credit Facility restricts us from~~ entering into ~~certain~~transactions ~~hedging contracts or extending credit. Our Senior Credit Facility also requires, and any future credit facilities may additionally require, us to comply~~ with ~~specified financial ratios, including regarding interest coverage, total leverage, current assets to current liabilities or other similar ratios.~~ affiliates;

We• ~~may~~creating ~~also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios~~ or ~~because~~incurring of the limitations imposed on us by the restrictive covenants under these agreements. The restrictions contained in our Senior Credit Facility and the 2011 Indenture may also limit our ability to plan for or react to market conditions, meet capital needs or otherwise restrict our activities or business plans and adversely affect our ability to finance our operations, enter into acquisitions, execute our business strategy, effectively compete with companies that are not similarly restricted or engage in other business activities that would be in our interest. In the future, we may also incur debt obligations that might subject us to additional and different restrictive covenants that could affect our financial and operational flexibility. We cannot assure you that we will be granted waivers or amendments to these agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on acceptable terms or at all should we seek to do so. liens;

~~Our~~• ~~ability~~transferring 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 breach of any of these provisions could result in a default under our Senior Credit Facility, the 2011 Indenture or ~~any~~selling future credit facilities we may enter into, which could allow all amounts outstanding thereunder to be declared immediately due and payable, subject to the terms and conditions of the documents governing such indebtedness. If we were unable to repay the accelerated amounts, our secured lenders could proceed against the collateral granted to them to secure such indebtedness. This would likely in turn trigger cross-acceleration and cross-default rights under any other credit facilities and indentures, if any then exist governing the notes and the terms of our other indebtedness outstanding at such time. If the amounts outstanding under our Senior Credit Facility, the 8.25% Senior Notes or any other indebtedness outstanding at such time were to be accelerated or were the subject of foreclosure actions, we assets;

20 • incurring dividend or other payment restrictions affecting certain subsidiaries;

~~cannot~~• ~~assure~~consummating ~~you~~a ~~that~~merger, ~~our~~consolidation ~~assets~~or ~~would~~sale beof ~~sufficient~~all ~~to repay in full the money owed to the lenders~~ or tosubstantially all our ~~other~~assets; ~~debt holders.~~ and

A• ~~substantial~~entering orinto ~~extended~~sale/leaseback decline in oil and natural gas prices may have a material adverse effect on our business, financial condition, results of operations, cash flows and our ability to meet our debt obligations, operating cost requirements, capital expenditure requirements and other financial commitmentstransactions.

~~The~~In ~~price~~addition, weunder ~~receive~~our ~~for~~revolving ~~our~~credit ~~oil~~facility, ~~and~~there ~~natural~~is ~~gas~~a ~~production~~restriction ~~heavily~~on ~~influences~~changes in our ~~revenue,~~management. ~~profitability,~~If ~~financial~~John ~~condition,~~D. ~~cash flow~~Schiller, ~~access~~Jr. ceases to ~~capital~~be ~~and~~the ~~future~~chief ~~rate~~executive officer of ~~growth.~~our ~~Oil~~parent ~~and~~company ~~natural~~Energy ~~gas~~XXI ~~are~~Ltd ~~commodities~~(except ~~and,~~ as a result, ~~their~~of ~~prices~~his ~~are~~death ~~subject~~or todisability) ~~wide~~and ~~fluctuations~~a inreasonably ~~response~~acceptable tosuccessor ~~relatively~~is ~~minor~~not ~~changes~~appointed inwithin ~~supply~~180 ~~and demand. Historically~~days, the ~~markets~~lenders ~~for~~of ~~oil~~our ~~and~~revolving ~~natural~~credit ~~gas~~facility ~~have~~could ~~been~~declare ~~volatile.~~amounts ~~While~~outstanding ~~oil~~thereunder ~~prices~~immediately ~~have~~due ~~recovered~~and ~~from~~payable. ~~their~~In ~~low levels in 2009, there are different views about~~ the ~~strength~~event ofthat ~~the~~Mr. ~~economic~~Schiller ~~recovery~~ceases ~~and~~to ~~future~~be ~~demand~~our ~~for~~parent’s ~~oil~~chief ~~and~~executive ~~natural gas. Consequently~~officer, ~~there~~amounts isoutstanding nounder ~~assurance~~our ~~that~~revolving ~~oil~~credit ~~prices~~facility ~~will~~would not ~~fall~~automatically ~~again.~~be ~~Domestic~~reclassified ~~natural~~as current ~~gas~~debt ~~prices~~as ~~have~~it ~~recently~~is ~~experienced~~probable ~~ten~~that ~~year~~we ~~lows~~could ~~and~~identify ~~may~~a ~~remain~~successor atwithin ~~these~~the ~~low~~180 ~~levels~~day ~~relative~~period. toOur ~~historical~~revolving ~~prices~~credit ~~for~~facility anrequires, ~~extended~~and ~~period~~any offuture ~~time.~~credit ~~The~~facilities ~~prices~~may werequire, ~~receive~~us ~~for~~to ~~our~~comply ~~production~~with ~~and~~specified ~~the~~financial ~~levels~~ratios, ofincluding ~~our~~regarding ~~production~~interest ~~depend~~coverage onand ~~numerous~~total ~~factors~~leverage ~~beyond our control~~coverage. ~~These factors include:~~

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 ~~•changes~~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 ~~global~~event ~~supply~~of acceleration of our outstanding indebtedness. In the event of such acceleration, ~~demand~~we ~~and~~cannot ~~inventories~~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 ~~oil;~~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.

•domesticWe naturalmay gasbe supply,able demandto andincur inventories;additional debt in the future. This could exacerbate the risks associated with our indebtedness.

~~•the~~Despite ~~actions~~our current level of indebtedness, we may incur more debt in the ~~Organization~~future, which could further exacerbate the risks described above. The terms of ~~Petroleum~~the ~~Exporting~~indentures ~~Countries;~~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.

•theContinued pricelow andcommodity quantityprices ofmay foreignimpact importsour ofability oil;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 ~~price~~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 ~~availability~~our parent’s other outstanding indebtedness. As of ~~liquefied~~June ~~natural~~30, ~~gas~~2015, ~~imports;~~EGC and our parent had outstanding indebtedness of $3,916 million, excluding all of our

~~•political conditions, including embargoes, in or affecting other oil-producing countries;~~ 20

~~•economic~~TABLE ~~and~~OF energy infrastructure disruptions caused by actual or threatened acts of war, or terrorist activities, or national security measures deployed to protect the United States from such actual or threatened acts or activities; CONTENTS

~~•economic~~indebtedness. ~~stability~~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 ~~major~~a ~~oil~~single ~~and~~debt ~~natural~~instrument. ~~gas~~If ~~companies~~an event of default occurs, or if other debt agreements cross-default, and the ~~interdependence~~lenders under the affected debt agreements accelerate the maturity of ~~oil~~any ~~and~~loans ~~natural~~or ~~gas~~other ~~and~~debt ~~energy~~outstanding, ~~trading~~we ~~companies;~~may not have sufficient liquidity to repay all of our outstanding indebtedness.

•theWe levelexpect ofto worldwidehave oilsubstantial capital requirements, and naturalwe gasmay explorationbe andunable productionto activity;obtain needed financing on satisfactory terms.

~~•weather~~We ~~conditions~~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, ~~including~~if ~~energy~~our ~~infrastructure~~capital ~~disruptions~~requirements ~~resulting~~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.

~~•technological~~The ~~advances~~cost ~~affecting~~of ~~energy~~raising ~~consumption;~~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 ~~price~~credit market and ~~availability~~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 ~~fuels~~financing, the terms of which may be less favorable to us, or not pursue growth opportunities.

~~Oil~~Without ~~prices~~additional ascapital ofresources, ~~the~~we ~~date~~may ofbe ~~this~~forced ~~Annual~~to ~~Report~~limit ~~permit~~or usdefer toour ~~maintain~~planned ~~the~~natural ~~minimal~~gas ~~investment~~and ~~necessary~~oil toexploration ~~mitigate~~and development program and this will adversely affect the ~~impact~~recoverability and ultimate value of our natural ~~reservoir~~gas ~~declines~~and onoil properties, in turn negatively affecting our ~~current~~business, ~~production~~financial ~~levels~~condition and results of operations. ~~However,~~We ifmay ~~oil~~also ~~prices~~be ~~fall~~unable to ~~their~~obtain ~~previous~~sufficient ~~low~~credit ~~levels,~~capacity wewith ~~may~~counterparties ~~not~~to befinance ~~able~~the tohedging ~~replace~~of our ~~reserves~~future crude oil and ~~our~~natural gas production which may ~~decline~~limit ~~significantly~~our ability to manage price risk. As a result, we ~~could~~may ~~experience~~lack athe ~~decline~~capital innecessary ~~our~~to ~~revenues~~obtain ~~and~~credit ~~available~~necessary ~~capital,~~to ~~which~~enter ~~would~~into derivative ~~likely~~contracts ~~substantially~~to ~~decrease~~hedge our ~~capital~~future ~~expenditures,~~crude ~~drilling~~oil ~~activities~~ and ~~operations~~natural gas production or to capitalize on other business opportunities.

OurWe currenthave operationsbeen andasked aby significant part of the valueBOEM ofto ourobtain productionbonds andor reservesother aresurety concentrated in theorder Gulfto ofmaintain Mexico.compliance Becausewith ofBOEM this concentrationregulations, anywhich productionmay problems,be impactscostly ofand adverse weather conditions or inaccuracies in reserve estimates related to these areas could havepotentially areduce materialborrowings adverseavailable effectunder on our business.revolving credit facility.

~~Virtually~~To ~~all~~cover the various obligations of ~~our~~lessees ~~current~~on ~~operations~~the ~~are~~OCS, ~~concentrated~~such inas 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 ~~region.~~operator, Wethe ~~are~~BOEM ~~more~~indicated ~~vulnerable~~that toit ~~operational~~may review the estimated cost of future plugging, ~~regulatory~~abandonment, decommissioning and removal obligations of other ~~risks~~OCS ~~associated~~operators, ~~with~~may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the ~~Gulf~~amount of ~~Mexico~~financial assurance required with respect to these obligations. In April 2015, ~~including~~we received letters from the ~~risk~~BOEM stating that certain of ~~adverse~~our ~~weather~~subsidiaries ~~conditions~~no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, ~~than~~plugging ~~many~~and abandonment liabilities. The letters notified us that certain of our ~~competitors~~subsidiaries ~~that~~must ~~are~~provide ~~more~~approximately ~~geographically~~$566.5 ~~diversified~~million ~~because~~in ~~all~~supplemental financial assurance and/or abonding ~~substantial~~for ~~portion~~their offshore oil and gas leases, rights-of-way, ~~our~~and ~~operations~~rights-of-use ~~could~~and ~~experience~~easements. ~~the~~In ~~same~~June ~~condition~~2015, atwe reached agreements with the ~~same~~BOEM ~~time~~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

At December 31, 2013, the Ship Shoal 208, East Bay and West Delta fields contained approximately 24%, 17%, and 15%, respectively, of our estimated proved reserves. If the actual reserves associated with these properties are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows. 21

~~During~~TABLE ~~the~~OF 2008 hurricane season, our production was reduced by approximately 21%, on an annual basis, 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 in these areas, such a curtailment could have a material adverse effect on our business, financial condition, results of operations and cash flows. CONTENTS

21 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.

~~The~~On ~~relatively~~September ~~steep~~22, ~~decline~~2015, ~~curves~~the ~~generally~~BOEM ~~associated~~issued Draft Guidance relating to supplemental bonding procedures that will, among other things, eliminate the “waiver” exemption currently allowed by BOEM with ~~oil~~respect to supplemental bonding and, ~~gas~~instead, ~~properties~~broaden ~~located~~the inself-insurance approach that would allow more operators on the ~~Gulf~~OCS to seek self-insurance for a portion of ~~Mexico~~their ~~region~~supplemental ~~subjects~~bond usobligations, tobut ~~higher~~only ~~reserve~~for ~~replacement~~an ~~needs~~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.

~~Producing~~We ~~oil~~currently maintain approximately $58.3 million in lease and/or ~~natural~~area ~~gas~~bonds ~~reservoirs~~issued ~~generally~~to ~~are~~the ~~characterized~~BOEM byand ~~declining~~approximately ~~production~~$122.5 ~~rates~~million ~~that~~in ~~vary~~bonds ~~depending~~issued ~~upon~~to ~~reservoir~~predecessor ~~characteristics~~third party assignors of certain wells and ~~other~~facilities ~~factors.~~on ~~High~~leases ~~initial~~pursuant ~~production~~to ~~rates~~a ~~generally~~contractual ~~result~~commitment inmade ~~recovery~~by ofus ato ~~relatively~~those ~~higher~~third ~~percentage~~parties at the time of ~~reserves~~assignment ~~from~~with ~~properties~~respect ~~during~~to the ~~initial~~eventual ~~few~~decommissioning ~~years~~of those wells and facilities. Thus, our total supplemental bonding is approximately $180.8 million, with an annual premium expense of ~~production~~$2.7 million. In addition, ~~often~~since ~~followed~~June by2015, awe ~~rapid~~have ~~decline~~received additional letters from the BOEM in which the ~~rate~~BOEM requests additional supplemental bonding for certain other properties previously exempt from supplemental bonding, generally as a result of ~~production~~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.

~~Because~~Although ~~substantially~~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 ~~operations~~properties. ~~are~~Furthermore, ~~concentrated~~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 ~~Gulf~~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 ~~Mexico~~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 ~~because~~results ~~production~~of ~~from~~operations. ~~reservoirs~~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 ~~Gulf~~amount of ~~Mexico~~any ~~region~~such ~~generally~~letter ~~declines~~of ~~more~~credit ~~rapidly~~obligations. ~~compared~~We can provide no assurance that we can continue to ~~reservoirs~~obtain inbonds ~~many~~or other ~~producing~~surety ~~regions~~in ofall cases, and if we are unable to obtain the ~~world~~additional required bonds or assurances as requested, the BOEM may require any of our ~~reserve~~operations ~~replacement~~on ~~needs~~federal ~~are~~leases ~~relatively~~to ~~greater~~be ~~than~~suspended ~~those~~or ofterminated, ~~producers~~and ~~with~~such ~~reserves~~action ~~outside~~could ~~the~~have ~~Gulf~~a material adverse effect on our business, prospects, results of ~~Mexico~~operations, ~~region~~financial condition, and liquidity.

AsOur ofestimates December 31, 2013, our independent petroleum engineers estimate that, on average, 60% of ourfuture totalasset provedretirement reservesobligations willmay bevary producedsignificantly withinfrom fiveperiod years. We will have to continueperiod toand develop,are exploit,especially findsignificant orbecause acquire additional reserves to sustain our currentoperations productioninclude levelsthe andU.S. toGulf growof our productionMexico.

~~The~~We ~~cost~~are ofrequired ~~operating~~to ~~our~~record ~~business,~~a ~~including~~liability ~~our~~for ~~estimates~~the discounted present value of ~~future~~our asset retirement obligations to plug and abandon inactive, ~~may~~non-producing ~~vary~~wells, ~~significantly~~to ~~especially~~remove ~~because~~inactive ~~our~~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 ~~concentrated~~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

We are responsible for plugging and abandoning wellbores and decommissioning associated platforms, pipelines and facilities on our oil and natural gas properties. Estimating future abandonment and decommissioning costs in the Gulf of Mexico is difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and technologies are constantly evolving, which may result in increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations (“ARO”) in future periods. Some of our offshore operations are conducted on federal leases that are administered by the BOEM and are required to comply with the regulations and orders promulgated by the BOEM and BSEE under OCSLA. We are subject to regulations over the decommissioning of wells and platforms. The regulations impose stringent requirements for decommissioning facilities that pose a hazard to safety or the environment, as well as for facilities that are not useful for lease operations and that are not capable of oil and natural gas production in “paying quantities.” The regulations also impose deadlines for removing platforms or other facilities that are no longer useful for operations, and deadlines for plugging, abandoning or performing downhole zonal isolation on wells that are no longer useful for operations and that are no longer capable of production in paying quantities. 22

~~Because~~TABLE weOF operate in the 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 materially if the platform from which the work was anticipated to be performed is damaged or toppled. Accordingly, our estimates of future abandonment and decommissioning costs could differ materially from what we may ultimately incur. The effects of Hurricanes Katrina and Rita during the 2005 hurricane season and Hurricanes Ike and Gustav in 2008 significantly impacted oil and gas operations on the OCS. The effects included structural damage to fixed production facilities, semi-submersibles and jack-up drilling rigs which could create the potential for catastrophic damage to key infrastructure and the resultant pollution. The former BOEMRE has issued still active guidance through NTLs, aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. CONTENTS

Into ~~September~~our ~~2013,~~estimated ~~after~~asset ~~receiving~~retirement ~~further~~obligations ~~interpretations~~in offuture ~~the~~periods. ~~BSEE~~For ~~regulations~~example, ~~the~~because ~~estimated~~we ~~scope~~operate ofin ~~required~~the ~~work~~U.S. ~~increased~~Gulf ~~and our estimates~~ of ~~future abandonment and decommissioning costs increased. It is possible that similar~~Mexico, ~~if not more stringent~~platforms, ~~design~~facilities and ~~operational~~equipment ~~requirements~~are ~~will~~subject beto ~~issued~~damage ~~by the BOEM~~ or ~~BSEE~~destruction inas ~~the~~a ~~future~~result ~~and~~of ~~these~~hurricanes. ~~new~~The ~~requirements~~estimated ~~could~~cost ~~further~~to ~~increase~~plug ~~our~~and ~~operating~~abandon ~~costs.~~a ~~The~~well ~~BOEM,~~or ~~BSEE~~dismantle ~~and~~a ~~other~~platform ~~regulatory~~can ~~bodies,~~change ~~including~~dramatically ~~those~~if ~~regulating~~ the ~~decommissioning~~host ofplatform ~~our~~from ~~pipelines~~which ~~and facilities under~~ the ~~jurisdiction~~work ofwas ~~the~~anticipated ~~state~~to ofbe ~~Louisiana,~~performed ~~may~~is ~~change~~damaged ~~their requirements~~ or ~~enforce~~toppled ~~requirements~~rather inthan astructurally ~~manner~~intact. ~~inconsistent~~Accordingly, ~~with~~ our ~~expectations,~~estimate ~~which could materially increase the cost~~ of ~~such~~future ~~activities~~asset ~~and/or~~retirement ~~accelerate~~obligations ~~the timing of cash expenditures and~~ could ~~have~~differ adramatically ~~material~~from ~~adverse~~what ~~effect~~we onmay ~~our~~ultimately ~~financial~~incur ~~position,~~as ~~results~~a result of ~~operations~~damage ~~and~~from ~~cash~~a ~~flows~~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 Wefinal ~~may~~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 ~~able~~permanently toplugged ~~keep~~or ~~pace~~temporarily ~~with~~abandoned ~~technological~~within ~~developments~~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 ~~industry~~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.

~~The~~In ~~oil~~addition ~~and~~to ~~natural~~the ~~gas~~Draft ~~industry~~Guidance isdescribing ~~characterized~~revised supplemental bonding procedures that may be used by ~~rapid~~the ~~and~~BOEM, ~~significant~~in ~~technological~~August ~~advancements~~2014, ~~and~~the ~~introductions~~BOEM ofissued ~~new~~an ~~products~~ANPR ~~and~~in ~~services~~which ~~using~~the ~~new~~agency ~~technologies.~~indicated Asthat ~~others~~it ~~use~~was orconsidering ~~develop~~increasing ~~new~~the ~~technologies,~~financial weassurance ~~may~~requirements bemandated ~~placed~~by atrule. aThe ~~competitive~~cost ~~disadvantage~~of orcompliance ~~competitive~~with ~~pressures~~our ~~may~~existing ~~force~~supplemental usbonding requirements or any other changes to ~~implement~~the ~~those~~BOEM’s ~~new~~current ~~technologies~~bonding atrequirements ~~substantial~~or ~~costs.~~regulations Inapplicable ~~addition,~~to ~~other~~us ~~natural~~or ~~gas~~our properties could be substantial and ~~oil~~could ~~companies~~materially ~~may~~and ~~have~~adversely ~~greater~~affect our financial condition, ~~technical~~cash flows, and ~~personnel~~results ~~resources~~of ~~that~~operations. ~~allow~~We ~~them~~can toprovide ~~enjoy~~no ~~technological~~assurance ~~advantages~~that ~~and~~we can ~~may~~continue into ~~the~~obtain ~~future~~bonds ~~allow~~or ~~them~~other tosurety ~~implement~~in ~~new~~all ~~technologies~~cases, ~~before~~and if we ~~can.~~are Weunable ~~may~~to ~~not~~obtain bethe ~~able~~additional torequired ~~respond~~bonds toor ~~these~~assurances ~~competitive~~as ~~pressures~~requested, ~~including~~ the ~~inability~~BOEM tomay ~~adapt~~require ~~technological~~any ~~advancements~~of toour aoperations ~~Gulf~~on offederal ~~Mexico~~leases ~~setting,~~to be suspended or ~~implement~~terminated, ~~new~~and ~~technologies~~such onaction could have a ~~timely~~material ~~basis~~adverse oreffect aton anour ~~acceptable~~business, ~~cost.~~prospects, Ifresults ~~one~~of oroperations, ~~more~~financial ofcondition, ~~the~~and ~~technologies~~liquidity. wePlease ~~use~~read ~~now~~“Risk orFactors — We inhave ~~the~~been ~~future~~asked ~~were~~by the BOEM to ~~become~~obtain ~~obsolete~~bonds or ifother wesurety ~~are~~in ~~unable~~order to ~~use~~maintain ~~the~~compliance ~~most~~with ~~advanced~~BOEM ~~commercially available technology~~regulations, ~~our~~which ~~business,~~may ~~financial~~be ~~condition,~~costly and ~~results~~could ofpotentially ~~operations~~reduce ~~could~~borrowings beavailable ~~materially~~under ~~adversely~~our ~~affected~~revolving credit facility.”

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

~~With~~Under ~~respect~~the full cost method of accounting, we are required to perform each quarter, a ~~portion~~“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, wenet ~~are~~of ~~not~~related deferred income taxes, plus the ~~operator~~cost of unevaluated oil and ~~therefore~~gas ~~are~~properties, ~~not~~exceeds inthe apresent ~~position~~value toof ~~control~~estimated future net cash flows discounted at 10%, net of related tax effects, plus the ~~timing~~cost of ~~development~~unevaluated ~~efforts~~oil and gas properties, the ~~associated~~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, orif prior to the ~~rate~~balance sheet date, we enter into certain hedging arrangements for a portion of our future natural gas and oil production, ofthereby enabling us to receive future cash flows that are higher than the ~~reserves~~estimated onfuture ~~such~~cash ~~properties~~flows indicated, these higher hedged prices are used if they qualify as cash flow hedges.

As we carry out our planned drilling program, we will not serve as operator of all planned wells. As of December 31, 2013, we operated approximately 89% of our properties, based on proved reserves at December 31, 2013. 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: 23

~~•the~~TABLE ~~timing~~OF ~~and amount of capital expenditures;~~ CONTENTS

•The recent declines in oil prices have adversely affected our financial position and results of operations and the ~~availability~~quantities of ~~suitable~~oil ~~offshore~~and ~~drilling~~natural ~~rigs,~~gas ~~drilling~~reserves ~~equipment,~~that ~~support~~we ~~vessels~~can economically produce. For the second, ~~production~~third and ~~transportation~~fourth ~~infrastructure~~quarters of fiscal year 2015, we recognized ceiling test write-downs of our oil and ~~qualified~~natural ~~operating~~gas ~~personnel;~~properties totaling $1,678.8 million.

•Based on the ~~operator’s~~average ~~expertise~~oil and ~~financial~~natural ~~resources;~~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.

•approvalThe present value of otherfuture participantsnet incash drillingflows wells;from our proved reserves is not necessarily the same as the current market value of our estimated reserves.

~~•selection~~This Form 10-K contains estimates of ~~technology;~~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 ~~rate~~volume, ofpricing ~~production~~and duration of ~~the~~our ~~reserves.~~natural gas and oil hedging contracts;

~~Our~~• ~~operations~~supply ~~in the deepwater Gulf~~ of ~~Mexico~~and ~~area~~demand ~~present~~for ~~unique~~natural ~~operating~~gas ~~risks.~~and oil;

~~The~~• ~~deepwater~~actual ~~Gulf~~prices ofwe ~~Mexico~~receive ~~area~~for ~~has~~natural ~~had~~gas ~~relatively limited drilling activity due to risks associated with geological complexity, water depth~~ and higher drilling and development costs, which could result in substantial cost overruns and/or uneconomic projects or wells. Because we have operations in the deepwater Gulf of Mexico area, we are exposed to these risks. oil;

If• weour ~~place~~actual ~~hedges~~operating oncosts ~~future~~in ~~production~~producing ~~and~~natural ~~encounter~~gas ~~difficulties~~and ~~meeting that production, we may not realize the originally anticipated cash flows.~~ oil;

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

~~Our~~• ~~price~~the ~~risk~~amount ~~management~~and ~~activities~~timing ~~could~~of ~~result~~actual inproduction; ~~financial losses or could reduce our income, which may adversely affect our cash flows.~~ and

We• ~~enter~~changes ~~into~~in ~~derivative~~governmental ~~contracts~~regulations toor ~~reduce the impact of oil and natural gas price volatility on our cash flow from operations~~taxation. ~~Currently, we use crude oil and natural gas swap arrangements to mitigate the volatility of future oil prices received.~~

~~Our~~The ~~actual~~timing ~~future~~of ~~production~~both ~~may~~our beproduction ~~significantly~~and ~~higher~~our orincurrence ~~lower~~of ~~than~~expenses wein ~~estimate~~connection atwith the ~~time~~development weand ~~enter~~production ~~into derivative contracts for such period. If the actual amount~~ of ~~production~~natural isgas ~~higher~~and ~~than~~oil weproperties ~~estimate, we~~ will ~~have~~affect ~~greater~~the ~~commodity~~timing ~~price~~of ~~exposure~~actual ~~than~~future wenet ~~intended~~cash asflows ~~our~~from ~~excess~~proved ~~production~~reserves, ~~will~~and bethus ~~unhedged.~~their ~~If the~~ actual ~~amount~~present ofvalue. ~~production~~In isaddition, ~~lower than~~ the ~~notional~~10% ~~amount~~discount ~~that~~factor ~~is subject to our derivative financial instruments,~~ we ~~might~~use bewhen ~~forced~~calculating todiscounted ~~satisfy~~future ~~all~~net orcash aflows ~~portion~~may ofnot ~~our~~be ~~derivative transactions at~~ the ~~current~~most ~~market~~appropriate ~~rates~~discount ~~without~~factor ~~the~~based ~~benefit~~on ofinterest ~~the~~rates ~~cash~~in ~~flow~~effect from ~~our~~time ~~sale~~to oftime ~~the~~and ~~underlying~~risks ~~physical~~associated ~~commodity,~~with ~~resulting~~us inor athe ~~substantial~~natural ~~diminution~~gas ofand ~~our~~oil ~~liquidity~~industry in general. AsAny amaterial ~~result~~inaccuracies ofin these ~~factors,~~reserve ~~our~~estimates ~~hedging~~or ~~activities~~underlying ~~may~~assumptions ~~not~~will bematerially affect asthe ~~effective~~quantities asand wepresent ~~intend~~value ~~in reducing the volatility~~ of our ~~cash flows~~reserves, ~~and~~which incould ~~certain~~adversely ~~circumstances~~affect ~~may actually increase the volatility of~~ our ~~cash flows. In addition~~business, ~~our~~results ~~price~~of ~~risk~~operations ~~management~~and ~~activities~~financial ~~are~~condition. ~~subject to the following risks:~~

•aOur counterpartyactual mayrecovery notof performreserves itsmay obligationdiffer underfrom theour applicableproved derivativereserve instrument; estimates.

~~•there~~This ~~may~~Form be10-K acontains ~~change~~estimates inof ~~the~~our ~~expected~~proved ~~differential~~oil ~~between~~and gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the ~~underlying~~available ~~commodity~~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 ~~derivative~~amount ~~instrument~~of oil and ~~the~~gas ~~actual~~that ~~price~~will ~~received;~~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

~~•the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.~~ 24

~~Loss~~TABLE ofOF ~~key management and failure to attract qualified management could negatively impact our operations.~~ CONTENTS

~~Successfully~~materially ~~implementing~~affect ~~our~~the ~~strategies~~estimated ~~will~~quantities ~~depend,~~of reserves shown in ~~part,~~the onreserve ~~our~~reports ~~management~~summarized ~~team~~in this Form 10-K. ~~The~~Actual ~~loss~~future ofproduction, ~~members~~oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of ~~our~~recoverable ~~management~~oil ~~team~~and ~~could~~gas ~~have~~reserves anmost ~~adverse~~likely ~~effect~~will onvary ~~our~~from ~~business~~estimates. ~~Our~~In ~~business~~addition, ~~will~~we ~~also~~may beadjust ~~dependent~~estimates ~~upon~~of ~~our~~proved ~~ability~~reserves to ~~attract~~reflect production history, results of exploration and ~~retain~~development, ~~qualified~~prevailing ~~personnel.~~oil ~~Acquiring~~and natural gas prices and ~~keeping~~other ~~qualified~~factors, ~~personnel~~many ~~could~~of ~~prove~~which ~~more~~are ~~difficult~~beyond orour ~~cost~~control.

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

~~substantially~~We ~~more~~have ~~than~~included ~~estimated.~~in ~~This~~this ~~could~~Form ~~cause~~10-K uscertain estimates of our proved reserves as of June 30, 2015 prepared in a manner consistent with our interpretation of the SEC rules relating to ~~incur~~modernizing ~~greater~~reserve ~~costs~~estimation and disclosure requirements for oil and natural gas companies, oras ~~prevent~~well usas ~~from~~the ~~pursuing~~interpretation of our ~~strategy~~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 ~~quickly~~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. ~~wish~~During the year ended June 30, 2015, we were required to doreduce proved reserve estimates by 2.8 Mmboe due to the five year development rule.

OurThe abilitydevelopment toof collectour paymentsproved fromundeveloped ourreserves partnersmay dependstake onlonger theand partners’may creditworthiness.require higher levels of capital expenditures than we currently anticipate.

InApproximately ~~operating~~24% of our ~~oil~~proved ~~and~~reserves ~~natural~~as ~~gas~~of ~~properties~~June 30, we2015 ~~typically~~were ~~incur~~proved ~~costs~~undeveloped onreserves ~~behalf~~and ofmay ~~our~~not ~~partners~~be inultimately ~~advance~~developed or produced. Recovery of ~~billing~~proved ~~and~~undeveloped ~~collecting~~reserves ~~our~~requires ~~partners’~~significant ~~share~~capital ofexpenditures ~~those~~and ~~costs~~successful drilling operations. ~~Some~~The ofreserves ~~our~~data ~~partners~~included ~~are~~in ~~highly~~the ~~leveraged~~reserves ~~and~~engineer ~~may~~reports ~~become~~assumes ~~unable~~that substantial capital expenditures are required to ~~pay~~develop ussuch ~~for~~reserves. ~~their~~We ~~share~~cannot ofbe certain that the ~~operating~~estimated costs. ~~Further,~~of athe ~~significant~~development ~~adverse~~of ~~change~~these inreserves ~~the~~are ~~financial~~accurate, ~~and/or~~that ~~credit~~development ~~position~~will ofoccur aas ~~partner~~scheduled ~~could~~or ~~require~~that usthe toresults ~~assume~~of ~~greater~~such ~~credit~~development ~~risk~~will ~~relating~~be toas ~~that~~estimated. ~~partner~~In ~~and~~addition, ~~could~~there ~~limit~~are external ~~our~~factors ~~ability~~such toas ~~collect~~such ~~joint~~as ~~interest~~changes ~~receivables.~~in ~~Failure~~commodity toprices, ~~receive~~the ~~payments~~availability ~~from~~of ~~our~~capital, ~~partners~~the ~~for~~availability ~~their~~of ~~share~~drilling rigs (capable of ~~costs~~drilling ~~incurred~~in onthe ~~our~~given ~~oil~~area), ~~and~~that ~~natural~~could ~~gas~~result ~~properties~~in ~~could~~certain ~~adversely~~development ~~affect~~plans ~~our~~being ~~results~~delayed ofand/or ~~operations,~~accelerated ~~financial~~relative ~~condition~~to ~~and~~the ~~cash~~current ~~flows~~schedule.

~~Provisions~~Delays in the development of our ~~organizational~~reserves ~~documents~~or increases in costs to drill and ~~under~~develop ~~Delaware~~such ~~law~~reserves ~~could~~will ~~delay~~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 ~~prevent~~write off of certain of our reserves as a ~~change~~result of lower oil and gas prices and reductions in ~~control~~our ofcapital expenditure budget as compared to our ~~company~~June 30, ~~which~~2014 ~~could~~reserve ~~adversely~~report. ~~affect~~Delays in the ~~price~~development of these reserves could cause us to have to reclassify our ~~common~~proved ~~stock~~reserves as unproved reserves. Please read “Business — Development of Proved Undeveloped Reserves.”

TheAs existence of someJune provisions30, in2015, ourapproximately organizational24% documentsof andour undertotal Delawareproved lawreserves couldwere delayundeveloped orand preventapproximately a23% change in control of our company,total whichproved couldreserves adverselywere affectdeveloped thenon-producing. priceThere ofcan ourbe commonno stock.assurance Thethat provisionsall in our Certificate of Incorporationthose andreserves Bylawswill thatultimately couldbe delaydeveloped or prevent an unsolicited change in control of our company include: produced.

•While we have plans or are in the ~~board~~process of ~~directors’~~developing ~~ability~~plans tofor ~~issue~~exploiting ~~shares~~and producing a majority of ~~preferred~~our ~~stock~~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 ~~determine~~developed non-producing reserves will ultimately be produced during the ~~terms~~time ofperiods we have planned, at the ~~preferred~~costs ~~stock~~we ~~without~~have ~~approval~~budgeted, or at all, which could result in the write-off of ~~common~~previously ~~stockholders;~~recognized ~~and~~reserves.

~~•a prohibition on the right of stockholders to call meetings and limitations on the right of stockholders to present proposals or make nominations at stockholder meetings.~~ 25

InTABLE ~~addition,~~OF ~~Delaware law imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.~~ CONTENTS

RisksUnless Relatedwe toreplace Ourcrude Acquisitionoil Strategyand natural gas reserves, our future reserves and production will decline.

~~Our~~A ~~acquisition~~large ~~strategy~~portion ~~involves~~of ~~potential~~our ~~risks~~drilling ~~that~~activity ~~could~~is ~~adversely~~located ~~impact~~in mature oil-producing areas of the GoM shelf. Accordingly, increases in our future ~~financial~~crude ~~performance~~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.

AProduction significantperiods componentor ofreserve ourlives businessfor strategyGulf isof toMexico acquireproperties oilsubject andus gasto properties.higher Acquisitionsreserve ofreplacement producingneeds propertiesand frommay thirdimpair partiesour requireability us to assessreduce manyproduction factorsduring thatperiods areof inherentlylow inexactoil and maynatural begas inaccurate, including: prices.

•High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the ~~risk~~Gulf ~~that~~of Mexico during the initial few years when compared to other regions in the U.S. Typically, 50% of the reserves ~~expected~~of properties in the Gulf of Mexico are depleted within three to ~~support~~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 ~~acquired~~Gulf ~~assets~~of ~~may~~Mexico ~~not~~generally bedecline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the ~~anticipated~~Gulf ~~magnitude~~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 ~~not~~limit beour ~~developed~~ability asto ~~anticipated;~~slow or shut in production from producing wells during periods of low prices for oil and natural gas.

•theThe riskborrowing thatbase financialunder informationour relatingrevolving tocredit facility may be reduced in the acquiredfuture assetsif commodity prices decline, which will limit our available funding for exploration and development. We may nothave bedifficulty accurate;obtaining additional credit, which could adversely affect our operations and financial position.

~~•inaccurate~~We ~~assumptions~~and ~~about~~EGC ~~revenues~~depend ~~and~~on ~~costs~~the revolving credit facility for a portion of its future capital needs. As of June 30, ~~including~~2015, ~~synergies;~~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.

~~•significant~~In ~~increases~~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 ~~our~~the ~~indebtedness~~borrowing ~~and~~base ~~working~~due ~~capital~~to ~~requirements;~~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 ~~inability~~early redetermination is possible. In addition, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to ~~transition~~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 ~~integrate~~oil ~~successfully~~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 ~~timely~~maintained, the ~~businesses~~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 ~~acquire;~~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

~~•the cost of transition and integration of data systems and processes;~~ 26

~~•potential~~TABLE ~~environmental~~OF ~~problems and costs;~~ CONTENTS

•collateral. We do not currently have any substantial properties which could serve as additional collateral, and we may not have the ~~assumption~~financial ofresources ~~unknown~~in ~~liabilities;~~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.

•limitationsOur onproduction, rightsrevenue toand indemnitycash flow from theoperating seller;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 ~~diversion~~resources ofto ~~management’s~~effectively ~~attention~~diversify our operations or benefit from ~~other~~the ~~business~~possible ~~concerns;~~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:

•~~increased~~ ~~demands~~subject onus ~~existing~~to ~~personnel~~numerous economic, competitive and onregulatory ~~our~~developments, ~~corporate~~any ~~structure~~or all of which may have an adverse impact upon the particular industry in which we operate; and

•~~increased~~ ~~responsibility~~result ~~for~~in ~~plugging~~our ~~and~~dependency ~~abandonment~~upon ~~costs;~~a single or limited number of hydrocarbon basins.

~~•customer~~In oraddition, ~~key~~the ~~employee~~geographic ~~losses~~concentration of our properties in the ~~acquired~~Gulf ~~businesses;~~of Mexico and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:

•~~the~~ ~~failure~~severe toweather, ~~realize~~such ~~expected~~as ~~growth~~hurricanes orand ~~profitability.~~other adverse weather conditions;

~~The~~• ~~scope~~delays ~~and~~or ~~cost~~decreases ofin ~~these~~production, ~~risks may ultimately be materially greater than estimated at~~ the ~~time~~availability of ~~the acquisition. Further~~equipment, ~~our~~facilities ~~future~~or acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future financial performance, results of operations and cash flows. Future transactions may prove to stretch our internal resources and infrastructure. As a result, we may need to hire additional personnel and invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely exacerbate these risks. services;

24 • delays or decreases in the availability of capacity to transport, gather or process production; and/or

We• ~~may~~changes ~~record~~in ~~material impairments to~~ the ~~carrying~~regulatory ~~values of our oil and natural gas properties if oil and gas prices decline from prices we used to estimate the acquisition fair values of acquired oil and gas properties~~environment.

WeDuring ~~record~~the ~~acquisitions~~2008 ofhurricane ~~oil~~season, ~~and~~production ~~natural~~from ~~gas~~certain of our properties ~~using~~was ~~the~~reduced ~~purchase~~as ~~method~~a result of ~~accounting~~damage ~~which~~to ~~requires~~third ~~that~~party wepipelines ~~record~~caused ~~the~~by ~~acquired~~two ~~oil~~hurricanes. ~~and~~The ~~natural~~hurricane ~~gas~~damage ~~properties~~limited atour ~~their~~ability ~~fair~~to ~~values~~sell asour production from certain properties for extended periods of time during the ~~acquisition~~third ~~date~~and fourth quarters of 2008. WeIf ~~may~~mechanical beproblems, ~~required~~storms or other events were to ~~recognize~~curtail ~~material~~a ~~non-cash~~substantial ~~impairment~~portion ~~charges~~of inthe ~~future~~production, ~~reporting~~such ~~periods~~a ifcurtailment ~~market~~could ~~prices~~have ~~for~~a ~~oil~~material oradverse ~~natural~~effect ~~gas~~on ~~decline~~our ~~and~~business, asfinancial acondition, ~~result~~results of operations and cash flows. In accordance with industry practice, ~~the~~we ~~estimated~~maintain ~~fair~~insurance ~~values~~against ofsome, but ~~the~~not ~~acquired~~all, ~~oil~~of these risks and ~~natural~~losses. ~~gas~~For ~~properties~~additional ~~decline~~information, ~~from~~please ~~the~~read ~~values~~“— Our ~~estimated~~insurance asmay not protect us against all of the ~~acquisition~~operating ~~date~~risks to which our business is exposed.”

WeBecause ~~may~~all beor ~~unable~~a tonumber ~~successfully~~of ~~integrate~~ the ~~operations~~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 weover ~~acquire~~a wider geographic area.

IntegrationThe ofnature the operations of the properties we acquire with our existing business willinvolves benumerous auncertainties complex, time-consuming and costlyoperating process.risks Failurethat tocan successfullyprevent integrateus thefrom acquiredrealizing businessesprofits and operationscan incause asubstantial timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flowslosses. The difficulties of combining the acquired operations include, among other things:

~~•operating~~We engage in exploration and development drilling activities, which are inherently risky. These activities may be unsuccessful for many reasons. In addition to a ~~significantly~~failure ~~larger~~to ~~combined~~find ~~organization;~~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.

~~•integrating corporate, technological and administrative functions;~~ 27

~~•integrating~~TABLE ~~internal~~OF ~~controls and other corporate governance matters;~~ CONTENTS

~~•diverting~~Our ~~management’s~~business ~~attention~~involves ~~from~~a ~~other~~variety ~~business~~of ~~concerns;~~operating risks, which include, but are not limited to:

•~~loss~~ ~~of key vendors from the acquired businesses~~fires;

•a ~~significant increase in our indebtedness~~explosions; ~~and~~

•~~potential~~ ~~environmental~~blow-outs ~~or regulatory liabilities~~ and ~~title~~surface ~~problems.~~ cratering;

~~The~~• ~~process~~uncontrollable offlows ~~integrating our operations could cause an interruption~~ of, ~~or loss of momentum in~~gas, ~~the~~oil activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer. Our operating performance, revenues and ~~costs~~formation ~~could be materially adversely affected if:~~ water;

•we ~~are~~natural ~~not~~disasters, ~~successful~~such inas ~~completing~~hurricanes ~~the~~and ~~integration~~other ofadverse ~~acquired~~weather ~~properties into our operations~~conditions;

•~~the~~ ~~integration~~pipe, ~~takes~~cement, ~~longer~~subsea well or ispipeline ~~more complex than anticipated~~failures; or

•we ~~cannot~~casing ~~operate acquired properties as effectively as we anticipate.~~ collapses;

We• ~~may~~mechanical ~~not~~difficulties, ~~have~~such ~~fully~~as ~~identified~~lost ~~liabilities associated with properties~~ or ~~assets~~stuck weoil ~~acquire~~field ordrilling ~~obtained~~and ~~adequate~~service ~~protection from sellers against liabilities.~~ tools;

~~Our~~• ~~assessments~~abnormally ofpressured ~~potential~~formations; ~~acquisitions may not reveal all existing or potential problems with the subject properties or permit us to become adequately familiar with the properties in order to evaluate fully their deficiencies~~ and capabilities. In the course of our due diligence, we may not inspect every well, platform or pipeline. Our inspections may not identify structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. As a result, we may not realize all of the anticipated benefits from future acquisitions, such as increased earnings, cost savings and revenue enhancements.

~~The~~• ~~properties~~environmental wehazards, ~~acquire~~such ~~may not produce~~ as ~~projected~~gas leaks, ~~and~~oil ~~we may be unable to determine reserve potential~~spills, ~~identify~~pipeline ~~liabilities~~ruptures ~~associated~~and ~~with~~discharges ~~the~~of ~~acquired~~toxic ~~properties or obtain protection from sellers against such liabilities~~gases.

~~The~~If ~~properties~~ we ~~acquire~~experience ~~may~~any ~~not~~of ~~produce~~these ~~as expected~~problems, ~~may~~well ~~be in an unexpected condition and we may be subject to increased costs and liabilities~~bores, ~~including environmental liabilities. Although we review properties prior to acquisition in a manner consistent with industry practices~~platforms, ~~such~~gathering ~~reviews~~systems ~~are~~and ~~not~~processing ~~capable~~facilities ofcould ~~identifying~~be ~~all potential adverse conditions. Furthermore~~affected, wewhich ~~may~~could ~~not~~adversely beaffect ~~able to subject the preparation of reserve estimates for acquired properties to the same internal controls we have for the preparation of reserve estimates for~~ our ~~existing~~ability ~~properties. Generally, it is not feasible~~ to ~~review~~conduct ~~in depth every individual property involved in each acquisition~~operations. We ~~focus~~could ~~our~~also ~~review~~incur ~~efforts~~substantial onlosses ~~the~~due ~~higher-value~~to ~~properties~~costs and/or ~~properties~~liability ~~with~~incurred ~~known~~as ~~adverse conditions and will sample the remainder. However, even~~ a ~~detailed~~result ~~review~~ of records and properties and preparation of reserve reports in accordance with our internal controls may not necessarily reveal existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their condition, any deficiencies, and development potential. :

25 • injury or loss of life;

If• wesevere ~~are~~damage ~~unable~~ to ~~execute~~and ~~our~~destruction ~~acquisition~~of ~~strategy successfully~~property, ~~our~~natural ~~business~~resources ~~may~~and ~~not continue to grow.~~ equipment;

We• ~~intend~~pollution ~~to pursue opportunistic acquisitions that leverage our organizational strengths. However, we may not be able to identify~~ and ~~consummate~~other ~~future~~environmental acquisitions successfully, and assets that we do acquire may not yield anticipated benefits. Our failure to execute our acquisition strategy successfully in the future could limit our ability to continue to grow our business. damage;

~~Risks~~• ~~Related~~clean-up ~~to Our Industry~~ responsibilities;

~~Reserve~~• ~~estimates~~regulatory ~~depend~~investigation ~~on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities~~ and ~~estimated values of our reserves.~~ penalties;

~~The~~• ~~process~~suspension of ~~estimating~~our ~~oil~~operations; and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves disclosed in this Annual Report.

~~Estimates~~• ofrepairs oil and natural gas reserves are inherently imprecise. The preparation of our reserve estimates requires projections of production rates and timing of development expenditures, analysis of available geological, geophysical, production and engineering data, and assumptions about oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The extent, quality and reliability of this data can vary. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, drilling and operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. If our estimates of the recoverable reserve volumes on a property are revised downward, if development costs exceed previous estimates or if commodity prices decrease, as discussed elsewhere in these risk factors, we may be required to ~~record~~resume ~~an impairment to our property and equipment, which could have a material adverse effect on our financial position and results of~~ operations. Once recorded, an impairment of property and equipment may not be reversed at a later date. Our ability to obtain financing in the future may depend in part on our estimate of the proved oil and natural gas reserves for properties that will serve as collateral. If proved reserves on a property are revised downward, our ability to acquire adequate funding may be significantly reduced.

TheOur presentoffshore valueoperations ofinvolve futurespecial netrisks cashthat flowscould fromaffect our provedoperations reserves is not necessarily the same as the current market value of our estimated oil and natural gas reservesadversely.

~~The~~Offshore ~~present~~operations ~~value~~are subject to a variety of ~~future~~operating ~~net~~risks ~~revenues~~specific ~~from~~to ~~our~~the ~~proved~~marine ~~reserves~~environment, such as capsizing, collisions and ~~the~~damage ~~standardized~~or ~~measure~~loss offrom ~~discounted~~hurricanes ~~future~~or ~~net~~other ~~cash~~adverse ~~flows~~weather ~~referred~~conditions. These conditions can cause substantial damage to infacilities ~~this~~and ~~Annual~~interrupt ~~Report~~production. ~~should~~As ~~not~~a beresult, ~~assumed~~we tocould ~~represent~~incur substantial liabilities that could reduce or ~~approximate~~eliminate the ~~current~~funds ~~market~~available ~~value~~for ofexploration, ~~our~~development ~~estimated~~or ~~proved~~leasehold ~~oil~~acquisitions, or result in loss of equipment and ~~natural~~properties. ~~gas~~In ~~reserves~~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.

InUnanticipated accordancedecommissioning withcosts SECcould requirements,materially theadversely estimatedaffect discountedour future netfinancial cashposition flows from our proved reserves are computed using prices based on the unweighted, arithmetic average of the closing price on the first day of each of the twelve months during the preceding fiscal year and costsresults as of the date of the estimate held constant for the life of the reservesoperations. However, actual future net cash flows from our natural gas and oil properties will be affected by factors such as:

~~•the~~We ~~volume~~may become responsible for unanticipated costs associated with abandoning and reclaiming wells, ~~pricing~~facilities and ~~duration~~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 ~~natural~~financial ~~gas~~position and ~~oil~~results ~~hedging~~of ~~contracts;~~operations.

•supplyOur insurance may not protect us against all of andthe demandoperating forrisks naturalto gaswhich andour oil;business is exposed.

~~•actual~~We ~~prices~~maintain weinsurance ~~receive~~ for ~~natural~~some, ~~gas~~but not all, of the potential risks and ~~oil;~~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

~~•our actual operating costs in producing natural gas and oil;~~ 28

~~•the~~TABLE ~~amount~~OF ~~and timing of our capital expenditures and decommissioning costs;~~ CONTENTS

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 ~~amount~~payment of insurance proceeds could have a material adverse effect on our financial condition and ~~timing~~results of ~~actual~~operations. ~~production;~~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.

•changesWeather Based Insurance Linked Securities may not payout in governmentalcase regulationsof a hurricane or taxation.may not fully cover damage.

~~The~~We ~~timing~~utilize ofWeather ~~both~~Based ~~our~~Insurance ~~production~~Linked ~~and~~Securities (“Securities”) to supplement our ~~incurrence~~windstorm ofinsurance ~~expenses~~coverage into ~~connection~~mitigate ~~with~~potential ~~the~~loss ~~development~~to ~~and~~our ~~production~~most ofvaluable oil and ~~natural~~ gas properties ~~will~~from ~~affect~~hurricanes in the ~~timing~~Gulf of ~~actual~~Mexico. ~~future~~These ~~net~~Securities ~~cash~~are ~~flows~~generally ~~from~~structured ~~proved~~to ~~reserves,~~provide ~~and~~for ~~thus~~payments ~~their~~of ~~actual~~negotiated ~~present~~amounts ~~value.~~should Ina ~~addition,~~hurricane ~~the~~having ~~10%~~a ~~discount~~pre-established ~~factor~~category wepass ~~use~~within ~~when~~specific ~~calculating~~pre-defined ~~discounted~~areas ~~future~~encompassing ~~net~~our ~~cash~~oil ~~flows~~and ~~may~~gas ~~not~~producing befields. ~~the~~While ~~most~~these ~~appropriate~~Securities ~~discount~~are ~~factor~~meant ~~based~~to onprovide ~~interest~~some ~~rates~~excess inwindstorm ~~effect~~coverage, ~~from~~there ~~time~~can tobe ~~time~~no ~~and~~certainty ~~risks~~that ~~associated~~these ~~with~~Securities uswill ormeet the ~~oil~~payout ~~and~~criteria ~~natural~~even ~~gas~~if ~~industry~~there inis substantial ~~general.~~damage ~~Any~~by ~~material~~a ~~inaccuracies~~hurricane inof ~~these~~a ~~reserve~~lower ~~estimates~~category orthan ~~underlying~~that ~~assumptions~~specified ~~will~~in ~~materially affect~~ the ~~quantities~~Securities. ~~and~~In ~~present~~addition, ~~value~~the ofpayment ~~our~~made ~~reserves,~~may ~~which~~not ~~could~~be ~~adversely~~sufficient ~~affect~~to ~~our~~cover ~~business,~~any ~~results~~actual ofdamage ~~operations~~incurred ~~and~~from ~~financial~~a ~~condition~~storm.

26 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.

~~Our~~We ~~estimates~~operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of ~~proved~~our ~~reserves~~competitors are major or independent oil and ~~related~~gas ~~PV-10~~companies that possess and ~~standardized~~employ ~~measure~~financial ofresources ~~discounted~~that ~~future~~allow ~~net~~them ~~cash~~to ~~flows~~obtain ~~have~~substantially ~~been~~greater ~~prepared~~technical inand ~~accordance~~personnel resources than ours. We actively compete with other companies when acquiring new ~~SEC~~ ~~rules~~leases or oil and gas properties. For example, ~~which~~new ~~went~~leases ~~into~~acquired ~~effect~~from ~~for~~the ~~fiscal~~BOEM ~~years~~are ~~ending~~acquired onthrough ora ~~after~~“sealed ~~December 31~~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, ~~2009~~such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may ~~make~~be ~~comparisons~~able to ~~prior~~evaluate, ~~periods~~bid ~~difficult~~for and ~~could~~purchase ~~limit~~a greater number of properties and prospects than our ~~ability~~financial or personnel resources permit. Competitors may also be able to ~~book~~pay ~~additional~~more ~~proved~~for ~~undeveloped~~productive ~~reserves~~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.

This Annual Report presents estimates of our proved reserves, related PV-10 and standardized measure of discounted future net cash flows as of December 31, 2013, 2012 and 2011, all of which have been prepared and presented under new SEC rules. These new rules were effective for fiscal years ending on or after December 31, 2009, and require companies to prepare their reserves estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of the-month average pricing. The previous rules required that reserve estimates be calculated using year-end pricing. As a result of these changes, and because the new rules do not have a retroactive effect to periods that ended prior to December 31, 2009, direct comparisons to our prior period reserves amounts may be more difficult. 29

~~Another~~TABLE ~~impact~~OF of the new SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This new rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our future proved undeveloped reserves if we do not drill and develop those reserves within the required five-year timeframe. CONTENTS

TheMarket SECconditions hasor releasedtransportation onlyimpediments limitedmay interpretivehinder guidanceaccess regardingto reportingoil of reserve estimates under the new rules and maygas not issue further interpretive guidance on the new rules. Accordinglymarkets, thedelay estimatesproduction ofor increase our proved reserves included in this Annual Report could differ materially from any estimates we might prepare applying more specific SEC interpretive guidancecosts.

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 ~~limited~~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 ~~book~~sell ~~additional~~our ~~proved~~oil ~~undeveloped~~and ~~reserves~~natural ~~under~~gas ~~recent~~may ~~SEC~~have ~~rules~~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.

WeMost have included in this Annual Report certain estimates of our provedundeveloped reservesleasehold asacreage of December 31, 2013 prepared in a manner consistent with our and our independent petroleum engineer’s interpretation of the recent SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies. These recent rules were effective for annual reporting periods ended on or after December 31, 2009. Included within these recent SEC reserve rules is a general requirement that, subject to limitedleases exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that theywill areexpire scheduledover tothe benext drilledseveral within five years ofunless theproduction dateis ofestablished booking.on Thisunits rulecontaining maythe limit our potential to book additional proved undeveloped reserves as we pursue our drilling programacreage. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, we may be required to write-off reserves previously recognized as proved undeveloped. As of December 31, 2013, approximately 29% of our total proved reserves were undeveloped, and approximately 29% of our total proved reserves were developed non-producing reserves. There can be no assurance that all of those reserves will ultimately be developed or produced.

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 ~~are~~will ~~unable~~lose our right to ~~replace~~develop the ~~reserves~~related ~~that~~properties. weWe currently do not have ~~produced~~leases expiring in fiscal years 2016 or 2017, but leases covering approximately 21% of our ~~reserves~~net ~~and~~acreage ~~future~~could ~~revenues~~potentially ~~will~~expire ~~decline~~in fiscal year 2018.

Our ~~future~~drilling ~~success~~plans ~~depends~~for onareas ~~our~~not ~~ability~~currently toheld ~~find,~~by ~~develop,~~production ~~acquire~~are ~~and~~subject ~~produce~~to ~~oil~~change ~~and~~based ~~natural~~upon ~~gas~~various ~~reserves~~factors, including factors that are ~~economically~~beyond ~~recoverable.~~our ~~Lower~~control, ~~commodity~~including ~~prices~~drilling ~~and increased costs associated with exploration~~results, ~~development~~oil and ~~production~~natural ~~may~~gas ~~lower~~prices, the ~~threshold~~availability ofand ~~economic~~cost ~~recoverability.~~of ~~Though our 2014 fiscal year~~ capital, ~~budget~~drilling ~~contemplates~~and ~~the~~production ~~deployment~~costs, availability of adrilling ~~larger~~services ~~amount~~and ofequipment, ~~capital~~gathering ~~compared~~system toand ~~the~~pipeline ~~capital~~transportation ~~expenditures~~constraints inand ~~2013,~~regulatory ~~there~~approvals. ~~can~~On beour noacreage ~~assurance~~ that we ~~will~~do benot ~~able~~operate, ~~to grow production through the drill-bit at rates~~ we have ~~experienced~~less incontrol over the ~~past.~~timing ~~Though~~of ~~we intend to pursue development and acquisition opportunities~~drilling, therefore there is noadditional ~~assurance~~risk ~~that our efforts will yield their intended results. Without continued successful acquisition or exploration activities, our reserves and revenues will decline as a result~~ of ~~our~~expirations ~~current~~occurring ~~reserves~~in ~~being~~those ~~depleted by production~~sections. ~~We may not be able to find or acquire additional reserves on an economic basis.~~

UnanticipatedWe decommissioningare costsnot couldthe materiallyoperator adverselyon affectall of our futureproperties financialand therefore are not in a position andto resultscontrol the timing of operations.development efforts, the associated costs, or the rate of production of the reserves on such properties.

WeAs ~~may~~we ~~become~~carry ~~responsible~~out ~~for~~our ~~unanticipated~~planned ~~costs~~drilling ~~associated~~program, ~~with~~we ~~abandoning~~will ~~and~~not ~~reclaiming~~serve ~~wells,~~as ~~facilities~~operator ~~and~~of ~~pipelines~~all planned wells. ~~Abandonment~~We ~~and~~operated ~~reclamation~~approximately 88% of ~~facilities~~our ~~and~~proved ~~the~~reserves ~~costs~~(including ~~associated~~approximately ~~therewith~~24% ~~are~~attributable ~~often~~to ~~referred~~the toSouth asPass ~~“decommissioning.”~~49 ~~Should~~field ~~decommissioning~~operated beby ~~required~~Energy ~~that~~XXI) isat ~~not~~June ~~presently~~30, ~~anticipated~~2015. As a result, orwe ~~should~~may ~~the~~have ~~decommissioning~~limited beability ~~accelerated~~to ~~(such~~exercise asinfluence ~~can~~over ~~happen~~the ~~after~~operations aof ~~hurricane),~~some ~~these~~non-operated properties or their associated costs. ~~may~~Dependence ~~exceed~~on the ~~value~~operator ofand ~~reserves~~other ~~remaining~~working atinterest ~~any~~owners ~~particular~~for ~~time.~~these Weprojects, ~~may~~and ~~have~~limited ability to ~~draw~~influence onoperations ~~funds~~and ~~from~~associated ~~other~~costs ~~sources~~could toprevent ~~satisfy~~the ~~such~~realization ~~costs~~of targeted returns on capital in drilling or acquisition activities. The ~~use~~success and timing of ~~other~~development ~~funds~~and toexploitation ~~satisfy~~activities ~~these~~on ~~decommissioning~~properties ~~costs~~operated ~~could~~by ~~have~~others adepend ~~material~~upon ~~adverse~~a ~~effect~~number onof ~~our~~factors ~~financial~~that ~~position~~will ~~and~~be ~~results~~largely outside of ~~operations.~~our control, including:

We• ~~may~~the ~~not~~timing beand ~~insured~~amount ~~against all~~ of ~~the~~capital ~~operating risks to which our business is exposed.~~ expenditures;

In• ~~accordance with industry practice, we maintain insurance coverage against some, but not all, of~~ the ~~operating~~availability ~~risks to which our business is exposed. We insure some, but not all,~~ of ~~our~~suitable ~~properties~~offshore ~~from~~drilling ~~operational and hurricane related events. We currently have insurance policies that include coverage for general liability~~rigs, ~~physical~~drilling ~~damage to our oil and gas properties~~equipment, ~~operational~~support ~~control of well~~vessels, ~~oil~~production ~~pollution, third party liability, workers’ compensation~~ and ~~employers’~~transportation ~~liability~~infrastructure and ~~other~~qualified ~~coverage.~~operating ~~Our insurance coverage includes deductibles that must be met prior to recovery, as well as sub-limits.~~ personnel;

27 • the operator’s expertise and financial resources;

~~Additionally,~~• ~~our~~approval ~~insurance~~of isother ~~subject~~participants toin ~~exclusions~~drilling ~~and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences and damages and losses.~~ wells;

Currently, we have general liability insurance coverage with an annual aggregate limit of $2.0 million and umbrella excess liabilities coverage with an aggregate limit of $200.0 million applicable to our working interests. Our general liability policy is subject to a $25,000 per incident deductible. We also have an offshore property physical damage and operators extra expense policies that contain an aggregate of $201.4 million of named windstorm limit of which we self-insure approximately 9%. Recoveries from these policies are subject to a $2.5 million deductible that applies to non-named windstorm occurrences and a $27.5 million deductible that applies to named windstorm events except for East Bay central facilities and rental compressor losses, which are subject to a 1.5% deductible of the scheduled values of the items making up a loss, but always subject to a $25,000 minimum. Further, there are sub-limits within the named windstorm annual aggregate limit for re-drill, non-blowout plugging and abandonment and excess removal of wreck. Our operational control of well coverage provides limits that vary by well location and depth and range from a combined single limit of $20 million to $75 million per occurrence. Deepwater wells have a coverage limit of $50 million per occurrence. Additionally, we maintain $150 million in oil pollution liability coverage as required under the Oil Pollution Act of 1990. Our control of well and oil pollution liability policy limits are scaled proportionately to our working interests, except for our deepwater control of well coverage, to which the $50 million limit applies to our working interest. Under our service agreements, including drilling contracts, generally we are indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider. 30

AnTABLE ~~operational~~OF or hurricane related event may cause damage or liability in excess of our coverage, which might materially adversely impact our financial position. We may be liable for damages from an event relating to a project in which we are a non-operator, but have a working interest in such project. Such an event may also cause a significant interruption to our business, which might also materially adversely impact our financial position. For example, we experienced production interruptions in 2005, 2006 and 2007 from Hurricanes Katrina and Rita, in 2008 and 2009 from Hurricanes Gustav and Ike for which we had no production interruption insurance. CONTENTS

We• ~~regularly~~selection ~~reevaluate the purchase~~ of ~~insurance,~~technology; ~~policy limits~~ and terms. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

We• ~~maintain an Oil Spill Response Plan (~~the ~~“Plan”)~~rate ~~that~~of ~~defines~~production ~~our~~of ~~response requirements and procedures and remediation plans in~~ the ~~event we have an oil spill~~reserves. Oil Spill Response Plans will generally be 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.

~~The~~Each ~~Company has contracted with an emergency and spill response management consultant, which would provide management expertise, personnel and equipment, under the supervision~~ of ~~the~~these ~~Company~~factors, inincluding ~~the event of an incident requiring a coordinated response. Additionally~~others, ~~the~~could ~~Company~~materially isadversely aaffect ~~member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in~~ the ~~Gulf~~realization of ~~Mexico~~our ~~and~~targeted ~~has~~returns ~~capabilities~~on tocapital ~~simultaneously respond to multiple spills. CGA is structured to provide an effective method of staging response equipment and providing spill response for its member companies~~ in ~~the~~drilling ~~Gulf~~or ofacquisition ~~Mexico.~~activities On January 1, 2013, CGA entered into an agreement with Clean Gulf Associates Services, LLC (“CGAS”), an affiliate of T&T Marine Salvage Inc. (“TTMS”). Through this agreement, CGAS will store, maintain, deploy and ~~operate~~lead all CGA-owned equipment and provide response personnel. This agreement replaced the expiring Equipment Management, Contractor Services and Bareboat Charter Agreement that CGA had previously entered into with Marine Spill Response Corporation. CGAS maintains CGA’s equipment in various warehouse locations (currently including 50 skimmers with various estimated daily recovery capacities, numerous containment and storage systems including thousands of feet of boom and one fire boom system, tanks and storage barges, wildlife cleaning and rehabilitation facilities, and both aerial and vessel dispersant spray systems) at staging points around the Gulf of Mexico in its ready state. In the event of a spill, CGAS mobilizes appropriate equipment to ~~CGA~~unexpected ~~members.~~future ~~In addition, CGA maintains a contract with Airborne Support Inc~~costs., ~~which provides aircraft and dispersant capabilities for CGA member companies.~~

AdditionalWe resources are availableexposed to thetrade Companycredit onrisk an as-needed basis other than as a member of CGA, such as those of CGAS. CGAS has oil spill response equipment independent of, and in addition to, CGA’s equipment. CGAS’s equipment currently includes, according to CGAS’s website, skimmer, containment boom, pumps and lightering equipment, vacuum units and sorbents. In the eventordinary course of aour spill,business CGAS activates contractors as necessary to provide additional resources or support services requested by its customersactivities.

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 28 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.

TheWe responsesell effectiveness, equipment and resources of these companies may change from time-to-time and current information is generally available on the websitesmajority of eachour ofproduction these organizations. There can be no assurances that the Company, together with the organizations described above will be able to effectivelythree manage all emergency and/or spill response activities that may arise and any failures to do so may materially adversely impact the Company’s financial position, results of operations and cash flowscustomers.

WeChevron, ~~may~~ConocoPhillips ~~incur substantial losses~~ and beShell ~~subject~~each toaccounted ~~substantial~~for ~~liability~~approximately ~~claims~~58%, as20%, aand ~~result~~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.

Losses and liabilities arising from uninsured and underinsured events could materially adversely affect our business, financial condition or results of operations. Our oilsuccess anddepends naturalon gasdedicated exploration and productionskillful activitiesmanagement are subject to all of the operating risks associated with drilling for and producingstaff, oilwhose anddeparture naturalcould gas,disrupt includingour thebusiness possibility of: operations.

~~•environmental~~Our ~~hazards,~~success ~~such~~depends ason ~~uncontrollable~~our ~~flows~~ability ofto ~~oil,~~retain ~~natural~~and ~~gas,~~attract ~~brine~~experienced engineers, ~~well~~geoscientists ~~fluids,~~and ~~toxic~~other ~~gas~~professional orstaff. ~~other~~We ~~pollution~~depend ~~into~~to a large extent on the ~~environment~~efforts, ~~including~~technical ~~groundwater~~expertise and ~~shoreline~~continued ~~contamination;~~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.

~~•abnormally~~Additionally, ~~pressured~~if ~~formations;~~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.

•blow-outsThe unavailability or high cost of drilling rigs, equipment, supplies, personnel and surfaceoil cratering;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.

~~•mechanical~~We ~~difficulties~~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 ~~pipe~~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, ~~cement~~equipment, ~~sub-sea~~supplies ~~well~~or personnel could delay or ~~pipeline~~adversely ~~failures;~~affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.

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

~~•personal~~Our ~~injuries~~assets ~~and~~consist ~~death;~~of ~~and~~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

~~•natural disasters, especially hurricanes and tropical storms in the Gulf of Mexico region.~~ 31

IfTABLE weOF 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 because of costs and/or liability incurred as a result of: CONTENTS

~~•injury~~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 ~~loss~~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 ~~life;~~the hedging contracts.

•severeOur damageprice torisk andmanagement destructionactivities ofcould propertyresult in financial losses or could reduce our income, naturalwhich resourcesmay andadversely equipment;affect our cash flows.

~~•pollution~~We enter into derivative contracts to reduce the impact of oil and ~~other~~natural ~~environmental~~gas ~~damage;~~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.

~~•clean-up~~Our ~~responsibilities;~~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:

•~~regulatory~~ ~~investigations~~a ~~and~~counterparty ~~penalties;~~may not perform its obligation under the applicable derivative instrument;

•~~suspension~~ ofproduction ~~our~~is ~~operations;~~less ~~and~~than expected;

•~~repairs~~ tothere ~~resume~~may ~~operations.~~be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and

~~Exploring~~• ~~for~~the ~~and~~steps ~~producing~~we ~~oil~~take ~~and~~to ~~natural~~monitor ~~gas~~our ~~are~~derivative ~~high-risk~~financial ~~activities~~instruments ~~with~~may ~~many~~not ~~uncertainties~~detect ~~that~~and ~~could~~prevent ~~adversely~~violations ~~affect~~of our ~~business,~~risk ~~financial~~management ~~condition~~policies orand ~~results of operations~~procedures.

~~Our~~During ~~future~~periods ~~success will depend on the success~~ of ~~our~~declining ~~exploration~~commodity ~~and~~prices, ~~production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond~~ our ~~control,~~commodity ~~including~~price ~~the~~derivative ~~risk~~positions ~~that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase~~increase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which ~~are~~increases ~~often~~our ~~inconclusive~~counterparty ~~or subject to varying interpretations~~exposure. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in planned expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling activity, including the following:

•pressureDeepwater oroperations irregularitiespresent inspecial geologicalrisks formations;that may adversely affect the cost and timing of reserve development.

~~•shortages~~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 ~~delays~~natural gas in ~~obtaining~~the ~~equipment~~deepwater of the Gulf of Mexico generally involves greater operational and ~~qualified~~financial ~~personnel;~~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.

~~•equipment failures or accidents;~~ 32

~~•adverse~~TABLE ~~weather~~OF ~~conditions, such as hurricanes and tropical storms;~~ CONTENTS

•reductionsAdditional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill response plans, and naturalother gasrelated prices;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 ~~•title~~drilling ~~problems;~~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.

~~•limitations~~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 ~~market~~future, ~~for~~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.

~~•cost~~Further, the deepwater areas of ~~services~~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 ~~drill~~quickly ~~wells~~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.

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

IfThe weconstruction ~~are~~and ~~unable~~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 ~~effectively~~obtain ~~manage~~all ~~the~~necessary ~~commodity~~permits ~~price~~and ~~risk~~approvals ofor obtain them in a timely manner, and as a result our ~~production~~operations ifmay ~~energy~~be ~~prices~~adversely ~~fall~~affected. In addition, weobtaining all necessary permits and approvals may ~~not~~necessitate ~~realize~~substantial expenditures to comply with the ~~anticipated~~requirements ~~cash~~of ~~flows~~these ~~from~~permits ~~our~~and ~~acquisitions.~~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.

ComparedOur tooperations some other participants in the oil and gas industry, we are asubject relatively small company with modest resources. Therefore, there is the possibility that we may be unable to findenvironmental counterpartiesand willingother togovernment enterlaws intoand derivativeregulations arrangements with us or, to the extent counterparties are willing to enter into derivative arrangements with us, we may be required to either purchase relatively expensive put options, or commit to deliver future production, in order to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to post cash collateral to counterparties as they mark to market these financial hedges. This funding requirement may limit the level of commodity price risk management that we are prudentlycostly able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energycould pricespotentially fall,subject weus may not be able to realizesubstantial the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reservesliabilities.

~~Periods~~As ofdescribed ~~high~~in ~~cost~~more ordetail ~~lack~~below, ofour ~~availability~~business ofactivities ~~drilling~~are ~~rigs,~~subject ~~equipment,~~to ~~supplies,~~regulation ~~personnel~~by ~~and~~multiple ~~oilfield~~federal, ~~services~~state ~~could~~and ~~adversely~~local ~~affect~~governmental ~~our~~agencies. ~~ability~~Our tohistorical ~~execute~~and onprojected aoperating ~~timely~~costs ~~basis~~reflect ~~our~~the ~~exploration~~recurring ~~and~~costs ~~development plans.~~

Substantially all of our current operations are concentrated in the Gulf of Mexico region. Shortages and the high cost of drilling rigs, equipment, supplies or personnel that occur in this region from time to time could delay or adversely affect our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Periodically, as a result of increased drilling activity or a decrease in the supply of equipment, materials and services, we have experienced increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in the Gulf of Mexico and in other offshore areas around the world also decreases the availability of offshore rigs in the Gulf of Mexico. As a result, costs may increase in the future and necessary equipment and services may not be available on terms acceptable to us. Redeployment of drilling rigs to areas other than the Gulf of Mexico in the wake of the Deepwater Horizon incident in April 2010, discussed below, may reduce the availability of offshore rigs, which could increase costs in future years. 33

~~Impediments~~TABLE toOF ~~transporting our products may limit our access to oil and natural gas markets or delay our production.~~ CONTENTS

~~Our~~resulting ~~ability~~from tocompliance ~~market~~with ~~our~~these ~~oil~~regulations, and ~~natural~~we ~~gas~~do ~~production~~not ~~depends~~anticipate onmaterial aexpenditures ~~number~~in excess of ~~factors,~~these ~~including~~amounts in the ~~proximity~~absence of ~~our~~future ~~reserves~~acquisitions toor ~~pipelines~~changes ~~and~~in ~~terminal facilities~~regulation, ~~the~~or ~~availability~~discovery ~~and capacity~~ of ~~gathering~~existing ~~systems,~~but ~~pipelines~~unknown ~~and~~compliance ~~processing~~issues. ~~facilities~~Additional ~~owned~~proposals and ~~operated~~proceedings bythat ~~third~~affect ~~parties and~~ the ~~availability of satisfactory~~ oil and ~~natural~~ gas ~~transportation~~industries ~~arrangements.~~are Inregularly ~~deepwater~~considered ~~operations~~by Congress, ~~market access depends on~~ the ~~proximity of~~states, ~~and~~regulatory ~~our~~commissions ~~ability~~and ~~to tie into~~agencies, ~~existing production platforms owned or operated by third parties~~ and the ~~ability~~courts. toWe ~~negotiate~~cannot ~~commercially~~predict ~~satisfactory~~when ~~arrangements with the owners~~ or ~~operators.~~whether ~~These~~any ~~facilities~~such ~~and~~proposals ~~systems~~ may bebecome ~~shut-in~~effective ~~due~~or tothe ~~factors~~magnitude ~~outside~~ of ~~our~~the ~~control.~~impact Ifchanges ~~any~~in oflaws ~~these third party services~~ and ~~arrangements~~regulations ~~become~~may ~~partially~~have ~~or fully unavailable, or if we are unable to secure such services and arrangements~~ on ~~acceptable~~our ~~terms~~business; however, oradditions ~~if the gas quality specification for their pipelines~~ or ~~facilities~~enhancements ~~changes so as~~ to ~~restrict~~the regulatory ~~our~~burden ~~ability to transport gas~~ on ~~these~~our ~~pipelines~~industry orgenerally ~~facilities,~~increase ~~our~~the ~~production~~cost ~~could~~of bedoing ~~limited~~business ~~or delayed~~ and affect our ~~revenues could be adversely affected~~profitability.

~~Competition~~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 ~~natural~~ gas industry isincreases ~~intense~~our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, ~~which~~we ~~may~~are ~~adversely~~unable ~~affect~~to uspredict the future cost or impact of complying with such laws.

WeAll ~~operate~~of inthe ajurisdictions ~~highly~~in ~~competitive~~which ~~environment~~we ~~for~~operate ~~acquiring~~generally ~~oil~~require ~~and~~permits ~~natural~~for ~~gas~~drilling ~~properties~~operations, ~~marketing~~drilling ~~oil~~bonds, and ~~natural~~reports ~~gas~~concerning operations and ~~securing~~impose ~~trained~~other ~~personnel.~~requirements ~~Many~~relating ofto ~~our~~the ~~competitors~~exploration ~~possess~~ and ~~employ~~production ~~financial, technical and personnel resources substantially greater than ours, which can be particularly important in Gulf~~ of ~~Mexico activities. Those companies may be able to pay more for productive~~ oil and ~~natural~~ gas. ~~properties~~Such ~~and~~jurisdictions ~~exploratory~~also ~~prospects~~have ~~and~~statutes ~~to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial~~ or ~~personnel~~regulations ~~resources~~addressing ~~permit.~~conservation ~~Our~~matters, ~~ability~~including toprovisions ~~acquire~~for ~~additional prospects and to discover reserves in~~ the ~~future~~unitization ~~will~~or ~~depend~~pooling onof ~~our~~oil ~~ability to evaluate~~ and ~~select~~gas ~~suitable~~ properties ~~and to consummate transactions in a highly competitive environment. Also~~, ~~there~~the isestablishment ~~substantial~~of ~~competition~~maximum ~~for~~rates ~~capital~~of ~~available~~production ~~for~~from ~~investment in the~~ oil and ~~natural~~ gas ~~industry.~~wells ~~There~~and ~~can be no assurance that we will be able to compete successfully in~~ the ~~future in acquiring prospective reserves~~spacing, ~~developing~~plugging ~~reserves, marketing hydrocarbons, attracting~~ and ~~retaining~~abandonment ~~quality~~of ~~personnel~~such ~~and raising additional capital~~wells. IfThe westatutes ~~are~~and ~~unable~~regulations toof ~~compete~~certain ~~successfully~~jurisdictions inalso ~~these~~limit ~~areas in~~ the ~~future,~~rate ~~our~~at ~~revenues~~which oil and ~~growth~~gas ~~may~~can be produced ~~diminished~~from orour ~~restricted~~properties.

~~The~~FERC ~~explosion~~regulates interstate natural gas transportation rates and ~~sinking~~terms of service, which affect the ~~Deepwater~~marketing ~~Horizon~~of ~~drilling~~gas ~~rig~~we inproduce, as well as the ~~Gulf~~revenues we receive for sales of ~~Mexico~~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 ~~April~~a ~~2010~~fundamental restructuring of interstate pipeline sales and transportation services, including the ~~resulting~~unbundling ~~oil~~by ~~spill~~interstate ~~may~~pipelines ~~significantly~~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 ~~risks~~ability to market and transport our gas, ~~costs~~although it may also subject us to greater competition and ~~delays~~to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.

~~The~~Our ~~explosion~~sales of oil and ~~sinking~~natural ofgas ~~the~~liquids ~~Deepwater~~are ~~Horizon~~not ~~drilling~~presently ~~rig~~regulated inand ~~the~~are ~~Gulf~~made ofat ~~Mexico~~market inprices. ~~April~~The ~~2010~~price ~~and~~we receive from the ~~resulting~~sale ~~oil~~of ~~spill~~those ~~may~~products ~~significantly~~is ~~impact~~affected by the ~~risks~~cost weof ~~face~~transporting the products to market. ~~The~~FERC ~~Deepwater~~has ~~Horizon~~implemented ~~incident~~regulations ~~and~~establishing ~~resulting~~an ~~legislative,~~indexing ~~regulatory~~methodology ~~and~~for ~~enforcement~~interstate ~~changes~~transportation rates for oil pipelines, ~~including~~which, ~~increased~~generally, ~~tort~~would ~~liability~~index such rate to inflation, ~~could~~subject ~~increase~~to ~~our~~certain ~~liability~~conditions and limitations. We are not able to predict with any certainty what effect, if any, ~~incidents~~these ~~occur~~regulations will have on ~~our~~us, ~~offshore~~but, ~~operations.~~other Wefactors ~~cannot~~being ~~predict~~equal, the ~~ultimate~~regulations ~~impact~~may, ~~the~~over ~~Deepwater~~time, ~~Horizon~~tend ~~incident~~to ~~and~~increase transportation ~~resulting~~costs ~~changes~~which inmay ~~regulation~~have the effect of ~~offshore~~reducing wellhead prices for oil and natural gas ~~operations will have on us~~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 30 to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.

InAlthough ~~response~~FERC has not made any formal determinations with respect to ~~the~~any ~~spill~~of our facilities, ~~and~~we ~~during~~believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a ~~moratorium~~pipeline onis ~~deepwater~~a ~~(below~~gathering ~~500~~pipeline ~~feet)~~and ~~drilling~~are ~~activities~~therefore ~~implemented~~not subject to FERC’s jurisdiction. The distinction between ~~May 30~~FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, ~~2010~~however, and, ~~October 12~~over time, ~~2010~~FERC’s policy for determining which facilities it regulates has changed. In addition, the ~~former~~distinction ~~BOEMRE~~between ~~issued~~FERC-regulated atransmission ~~series~~facilities, on ofthe ~~active~~one ~~NTLs~~hand, and ~~adopted~~gathering ~~changes~~facilities, toon ~~its~~the ~~regulations~~other, tois ~~impose~~a fact-based determination made by FERC on a ~~variety~~case-by-case ofbasis. ~~new~~If ~~measures~~FERC ~~intended~~were to ~~help~~consider ~~prevent~~the astatus ~~similar~~of ~~disaster~~an inindividual facility and determine that the ~~future.~~facility and/or services

Offshore operators, including those operating in deepwater, OCS waters and shallow waters, where we have substantial operations, must comply with strict new safety and operating requirements. For example, permit applications for drilling projects must meet new standards with respect to well design, casing and cementing, blowout preventers, safety certification, emergency response, and worker training. Operators of all offshore waters are also required to demonstrate the availability of adequate spill response and blowout containment resources. In addition, the BSEE imposed, for the first time, requirements that offshore operators maintain comprehensive safety and environmental programs. Such developments have the potential to increase our costs of doing business. Notwithstanding the lifting of the moratorium on October 12, 2010, there have been significant delays in permitting and an overall decline in the number of permits that have been issued. We anticipate that there will continue to be delays in permitting as these and possible additional regulatory initiatives are fully implemented. 34

~~Legislative~~TABLE ~~and~~OF regulatory initiatives relating to offshore operations, which include consideration of increases in the minimum levels of demonstrated financial responsibility required to conduct exploration and production operations on the outer continental shelf and elimination of liability limitations on damages, will, if adopted, likely result in increased costs and additional operating restrictions and could have a material adverse effect on our business. CONTENTS

Inprovided ~~addition~~by toit ~~new~~are ~~regulatory~~not ~~requirements,~~exempt ~~there~~from ~~have~~FERC ~~been~~regulation aunder ~~variety~~the ofNGA ~~proposals to change existing laws~~ and ~~regulations~~ that ~~could~~the ~~materially~~facility ~~adversely~~provides ~~affect~~interstate ~~our~~service, ~~operations~~the ~~and~~rates ~~cause us to incur substantial costs~~for, ~~including~~and byterms ~~raising~~and ~~operating~~conditions ~~costs~~of, ~~increasing~~services ~~insurance~~provided ~~premiums,~~by ~~delaying~~such ~~drilling~~facility ~~operations~~would ~~and~~be ~~increasing~~subject ~~regulatory~~to ~~burdens.~~regulation Weby ~~are~~FERC ~~not~~under ~~able to predict~~ the ~~likelihood~~NGA ~~of such proposals actually becoming law~~ or the ~~nature,~~Natural ~~extent~~Gas orPolicy ~~timing~~Act of ~~any~~1978 ~~interim or final rules that may result from such proposals~~(NGPA). IfSuch ~~enacted,~~regulation ~~such changes~~ could ~~lead~~decrease ~~to a wide variety of other unforeseeable consequences that make operations in the Gulf of Mexico and other offshore waters more difficult~~revenue, ~~more~~increase ~~time~~operating ~~consuming~~costs, and ~~more costly. For example~~, ~~there~~depending ~~have~~upon ~~been~~the ~~proposals~~facility in ~~the U.S. Congress to amend OPA~~question, ~~including~~could byadversely ~~eliminating~~affect ~~limits~~our onresults ~~liability~~of operations and ~~further~~cash ~~increasing applicable financial assurance requirements, in response to the Deepwater Horizon incident~~flows. IfIn ~~OPA were amended to materially increase the minimum level of financial responsibility beyond current requirements~~addition, weif ~~may~~any ~~experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level~~ of ~~financial~~our ~~assurance~~facilities ~~required~~were byfound ~~OPA, we may be forced~~ to ~~sell~~have ~~our~~provided ~~properties~~services or ~~operations~~otherwise ~~located~~operated in ~~offshore~~violation ~~waters~~of ~~or enter into partnerships with other companies that can meet~~ the ~~increased~~NGA ~~financial~~or ~~responsibility requirement~~NGPA, ~~and~~this ~~any such developments~~ could ~~have~~result anin ~~adverse effect on~~ the imposition ~~value~~ of ~~our~~civil ~~offshore~~penalties ~~assets~~as ~~and~~well ~~the~~as ~~results~~a ofrequirement ~~our~~to ~~operations.~~disgorge Wecharges ~~cannot~~collected ~~predict~~for ~~at this time whether or when any~~ such ~~changes~~service in ~~current~~excess ~~laws~~of ~~and~~the ~~regulations~~rate ~~will~~established ~~occur~~by FERC.

~~Recent~~State ~~hurricanes~~regulation inof ~~the~~gathering ~~Gulf~~facilities ofincludes ~~Mexico~~safety, ~~including~~environmental ~~Ivan~~and, ~~Katrina,~~in ~~Rita,~~some ~~Gustav and Ike~~circumstances, ~~caused~~nondiscriminatory ~~damage~~take torequirements aand ~~number~~in ofsome ~~unaffiliated~~instances ~~drilling~~complaint-based ~~rigs~~rate regulation. ~~BOEM~~ ~~and~~Our ~~BSEE~~gathering ~~issued~~operations ~~guidelines~~may ~~imposing~~also ~~new~~be ~~requirements~~subject ~~relating~~ to ~~tie-downs~~state onratable ~~drilling~~take ~~rigs~~ and ~~other~~common ~~permanent~~purchaser ~~equipment~~statutes, ~~attached~~designed to ~~outer~~prohibit ~~continental~~discrimination ~~shelf~~in ~~production~~favor ~~platforms~~of toone ~~increase~~producer ~~the~~over ~~likelihood~~another ofor ~~survival~~one source of ~~such~~supply ~~rigs~~over ~~during~~another. ~~hurricane~~State ~~events. The~~and ~~guidelines~~local ~~also~~regulation ~~impose~~may ~~new~~cause ~~data~~us ~~collection~~to ~~and~~incur ~~disclosure~~additional ~~requirements.~~costs ~~Such~~or ~~hurricane~~limit ~~protection~~our ~~measures,~~operations and ~~any~~can ~~new~~have orthe ~~more~~effect ~~stringent~~of ~~guidelines~~imposing orsome ~~formal~~restrictions ~~rules,~~on ~~may~~our ~~subject~~ability ~~our~~as ~~operations~~an owner of gathering facilities to ~~increased~~decide ~~costs~~with orwhom ~~limit~~we ~~operational~~contract ~~capabilities~~to gather ~~during~~natural ~~storm~~gas. ~~events~~Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

~~The~~Our ~~recent~~oil ~~reorganization~~and ofgas ~~the~~operations ~~former~~are ~~BOEMRE~~subject ~~may~~to ~~impact~~stringent ~~potential~~laws ~~future~~and regulations relating to the release or ~~enforcement~~disposal ~~that~~of ~~may~~materials ~~affect~~into ~~our~~the ~~operations~~environment or otherwise relating to environmental protection. These laws and regulations:

On• ~~October 1,~~require ~~2011,~~ the ~~U.S.~~acquisition ~~Department~~ of ~~the~~a ~~Interior~~permit ~~completed~~before ~~its~~drilling reorganization of the BOEMRE (formerly the Minerals Management Service) by dividing its offshore oil and gas responsibilities among three independent agencies. The first phase of reorganization took place in 2010 when the revenue collection arm of the former Minerals Management Service became the Office of Natural Resources Revenue. A year later the BOEMRE was replaced with the BOEM, which has responsibility for leasing and environmental studies, and the BSEE, which has responsibility for field operations, including inspections, regulatory compliance, and oil spill response. At this time, we cannot predict the impact that this reorganization, or future regulations or enforcement actions taken by the new agencies, may have on our operations. commences;

We• ~~may~~restrict ~~need~~the ~~to obtain bonds or other surety in order to maintain compliance with applicable regulations~~types, ~~which,~~quantities ~~if required, could be costly~~ and ~~reduce~~concentration ~~borrowings~~of ~~available~~substances ~~under~~that ~~our~~can ~~Senior~~be ~~Credit~~released ~~Facility~~into orthe ~~any~~environment ~~other~~in ~~credit~~connection ~~facilities~~with wedrilling ~~may~~and ~~enter~~production ~~into in the future.~~ activities;

~~Regulations~~• ~~with~~limit respect to offshore operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS of the Gulf of Mexico and removal of facilities. Lessees subject to these regulations are generally required to have substantial net worth or ~~post~~prohibit ~~bonds~~drilling oractivities ~~other acceptable assurances so that the various obligations of lessees~~ on ~~the~~certain ~~Gulf~~lands oflying ~~Mexico~~within ~~shelf will be met. While we believe that we are currently exempt from such supplemental bonding requirements~~wilderness, ~~the~~wetlands ~~BOEM or BSEE could re-evaluate or increase our obligations, which could cause us to lose our exemption. The cost of these bonds or other surety could be substantial~~ and ~~there is no assurance that bonds or~~ other ~~surety~~protected ~~could~~areas; ~~be obtained in all cases. 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~~ and

31 • impose substantial liabilities for pollution resulting from operations.

beFailure ~~issued~~to ~~under~~comply our Senior Credit Facility or another credit facility we may enter into in the future and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. The cost of compliance with these ~~supplemental~~laws ~~bonding requirements could materially~~ and ~~adversely~~regulations ~~affect~~may ~~our~~result ~~financial condition, cash flows and results of operations.~~ in:

We• ~~are subject to extensive governmental laws and regulations, including environmental regulations and permit requirements that can adversely affect~~ the ~~cost,~~imposition ~~manner or feasibility~~ of ~~doing~~administrative, ~~business~~civil and ~~could result in restrictions on our operations~~ /or ~~civil or~~ criminal ~~liability.~~ penalties;

~~Our~~• ~~exploration,~~incurring ~~development~~investigatory ~~and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing~~ or ~~otherwise~~remedial ~~handling~~obligations; ~~hydrocarbons~~ and related wastes are subject to various federal, state and local laws, orders and regulations. Such laws regulate, among other things, air emissions, water and stormwater discharges, releases of oil and hazardous substances and the development, implementation, inspection and maintenance of emergency response procedures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief, including possible suspension of our operations. Certain environmental laws impose strict liability for remediation of spills and releases of oil and hazardous substances, as well as for any resulting damage to natural resources, and can include claims by private parties as well as governmental agencies.

~~The~~• ~~construction~~the ~~and~~imposition ~~operation~~ of ~~our~~injunctive ~~projects also require numerous permits and approvals from governmental agencies. If we are unable to acquire or renew permits and approvals required for operations~~relief, wewhich ~~may~~could belimit ~~forced to suspend~~ or ~~cease~~restrict ~~operations altogether. We may not be able to obtain all necessary permits and approvals, and as a result~~ our operations ~~may be adversely affected~~. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures and 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.

InChanges ~~addition,~~in weenvironmental ~~are~~laws ~~required~~and toregulations ~~satisfy~~occur ~~insurance~~frequently, and ~~financial~~any ~~responsibility~~changes ~~requirements~~that ~~for~~result ~~potential~~in ~~oil~~more ~~spills~~stringent ~~and~~or ~~other~~costly ~~pollution~~waste ~~incidents. While~~handling, ~~our~~storage, ~~current~~transport, ~~insurance~~disposal ~~for~~or ~~such~~cleanup ~~events~~requirements iscould ~~consistent~~require ~~with~~us ~~the~~to ~~requirements~~make ofsignificant ~~OPA,~~expenditures ~~there~~to isattain noand ~~assurance~~maintain ~~that~~compliance ~~such~~and ~~coverage~~may ~~will~~otherwise ~~continue~~have toa bematerial ~~available~~adverse effect on our industry in ~~the~~general ~~future~~and on our own results of operations, competitive position or ~~that~~financial wecondition. ~~will~~Although bewe ~~able~~intend to ~~obtain~~be ~~such~~in ~~insurance. Even~~compliance ifin ~~insurance~~all ismaterial ~~available~~respects ~~and~~with weall ~~have~~applicable ~~obtained~~environmental ~~coverage,~~laws ~~the~~and ~~insurance~~regulations, ~~coverage~~we ~~may~~cannot ~~not~~assure beshareholders ~~adequate~~that towe ~~satisfy~~will ~~all~~be ~~resulting~~able ~~liabilities~~to ~~should~~comply awith ~~significant~~existing ~~claim~~or ~~occur~~new regulations. ~~Any~~ ofIn ~~these~~addition, ~~scenarios~~the ~~could~~risk ~~have~~of aaccidental ~~material~~spills, ~~adverse~~leakages ~~effect~~or onother ~~our~~circumstances ~~business,~~could ~~operating~~expose ~~results~~us ~~and~~to ~~financial~~extensive ~~condition~~liability.

WeUnder ~~are~~certain ~~exposed to claims under~~ environmental ~~requirements~~laws ~~and~~that ~~such~~impose ~~claims have been made against us. In the United States~~strict, ~~environmental~~joint ~~requirements~~ and ~~regulations~~several ~~typically impose strict~~ liability., ~~Strict liability means that in some situations~~ we could be ~~exposed~~held toliable ~~liability~~ for ~~cleanup~~the ~~costs,~~removal ~~natural~~or ~~resource~~remediation ~~damages,~~of ~~and~~previously ~~other~~released ~~damages~~materials asor aproperty ~~result~~contamination regardless of ~~our~~whether ~~conduct~~we ~~that~~were ~~was~~responsible ~~lawful~~for at the ~~time~~release ~~it occurred~~ or ~~the~~contamination, ~~conduct~~and regardless of ~~prior~~whether ~~operators~~current or ~~other~~prior ~~third~~operations ~~parties.~~were ~~Liability~~conducted ~~for~~in ~~damages~~compliance ~~arising~~with asall aapplicable ~~result of future claims brought under environmental~~ laws ~~could be substantial~~ and ~~could~~consistent ~~have~~with aaccepted ~~material~~standards ~~adverse~~of ~~effect~~practice onat ~~our~~the ~~financial~~time ~~position,~~those ~~results~~actions ofwere ~~operations,~~taken. ~~and~~In ~~cash flows~~addition, orclaims ~~any~~for ofdamages ~~them.~~to ~~These~~persons ~~potential~~or ~~liabilities~~property may ~~arise~~result from ~~both~~environmental ~~our historical operations~~ and ~~the~~other ~~historical~~impacts ~~operations~~ of ~~companies~~our ~~or properties that we have acquired~~operations. WeSuch ~~also~~liabilities ~~could~~can be ~~subject~~significant, toand ~~third-party~~if imposed ~~claims~~could ~~with~~have ~~respect~~a tomaterial ~~environmental~~adverse ~~matters~~effect ~~for~~on ~~which~~our wefinancial ~~have~~condition ~~been~~or ~~named~~results asof ~~a potentially responsible party~~operations.

~~Future~~We ~~compliance~~are ~~with~~unable ~~laws~~to ~~and~~predict ~~regulations,~~the ~~including~~effect ~~environmental,~~of ~~production,~~additional ~~transportation,~~environmental ~~sales,~~laws ~~rate~~ and ~~tax rules and~~ regulations, ~~and~~that ~~any changes to such laws or regulations,~~ may ~~reduce~~be ~~our~~adopted ~~profitability~~in ~~and~~the ~~have a material adverse effect on our financial position~~future, ~~liquidity~~including ~~and~~whether ~~cash~~any ~~flows.~~such ~~Such~~ laws ~~and~~or regulations ~~may~~would ~~require~~materially ~~more~~adversely ~~stringent~~increase ~~and~~our ~~costly~~cost ~~waste~~of ~~handling,~~doing ~~storage,~~business ~~transport, disposal~~ or ~~cleanup~~affect ~~requirements.~~operations ~~See~~in ~~“Business—Environmental~~any ~~Matters~~area.”

The adoption of climate change legislation could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce. 35

~~There~~TABLE ~~are~~OF state, national and international efforts to regulate the emission of greenhouse gases including, most significantly, carbon dioxide. The U.S. Congress has considered, but has not passed, legislation that seeks to control or reduce emissions of greenhouse gases from a variety of sources. In addition, several states have taken measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories or state-specific or regional cap-and-trade programs. It is uncertain at this time whether, and in what form, climate change legislation will ultimately be adopted in the United States. CONTENTS

InRate theregulation absencemay ofnot federalallow legislation,us the EPA is implementing regulations under the Clean Air Act pertaining to greenhouserecover gas emissions. In 2009, the EPAfull issuedamount a finding that greenhouse gas pollution endangers the public health and welfare and subsequently finalized a greenhouse gas emission standard for mobile sources. On November 8, 2010, the EPA issued greenhouse gas monitoring and reporting regulations specifically for petroleum and natural gas facilities, including offshore petroleum and natural gas production facilities that emit 25,000 metric tons or more of carbonincreases dioxidein equivalentour per yearcosts. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gas emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. The EPA issued a final rule that

32 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.

~~makes~~FERC’s ~~certain~~indexing ~~stationary~~methodology ~~sources~~is ~~and~~subject ~~modification~~to ~~projects~~review ~~subject~~every tofive ~~permitting~~years. ~~requirements~~The ~~for~~current ~~greenhouse~~or ~~gas~~any ~~emissions,~~revised ~~beginning~~indexing informula ~~2011,~~could ~~under~~hamper our ability to recover our costs because: (1) the ~~Clean~~indexing ~~Air~~methodology ~~Act. Challenges~~is tied to ~~certain~~an ofinflation ~~those~~index; ~~greenhouse~~(2) ~~gas~~it ~~rules~~is ~~were~~not ~~rejected~~based byon pipeline-specific costs; and (3) it could be reduced in comparison to the Dcurrent formula.C. ~~Circuit~~Any ~~Court~~ of ~~Appeals~~the foregoing would adversely affect our revenues and cash flow. ~~Requests~~ FERC could limit our pipeline’s ability to ~~reconsider~~set ~~are~~rates ~~pending~~based ~~but~~on its costs, ~~for~~order ~~the~~our ~~present~~pipelines to reduce rates, ~~implementation~~require ~~seems~~the ~~likely~~payment ~~although~~of ~~such~~refunds ~~rules~~or ~~may~~reparations ~~yet~~to beshippers, ~~modified~~or any or ~~the~~all ~~EPA~~of these actions, which could adversely ~~develop~~affect our financial position, cash flows, and results of operations. If FERC’s ratemaking methodology changes, the new ~~rules~~methodology could also result in tariffs that generate lower revenues and cash flow.

~~Legislation~~Based oron ~~regulations~~the ~~that~~way ~~may~~our beoil ~~adopted~~pipelines toare ~~address~~operated, ~~climate~~we ~~change~~believe ~~could~~that ~~also affect~~ the ~~markets~~only ~~for~~transportation on our ~~products~~pipelines bythat ~~making~~is ~~our~~subject ~~products~~to ~~more~~the orjurisdiction ~~less~~of ~~desirable~~FERC ~~than~~is ~~competing~~the ~~sources~~transportation ofspecified ~~energy.~~in To the ~~extent~~tariff ~~that~~we ~~our~~have ~~products~~on ~~are~~file ~~competing~~ with ~~higher~~FERC. ~~greenhouse~~We ~~gas~~cannot ~~emitting~~guarantee ~~energy~~that ~~sources~~the ~~such~~jurisdictional asstatus ~~coal,~~of transportation on our ~~products~~pipelines ~~would~~and ~~become~~related ~~more~~facilities ~~desirable~~will inremain ~~the~~unchanged, ~~market~~however. ~~with~~Should ~~more~~circumstances ~~stringent~~change, ~~limitations~~then oncurrently ~~greenhouse~~non-jurisdictional ~~gas~~transportation ~~emissions.~~could Tobe ~~the~~found ~~extent~~to ~~that~~be ~~our~~FERC-jurisdictional. ~~products~~In ~~are~~that ~~competing~~case, ~~with~~FERC’s ~~lower~~ratemaking ~~greenhouse~~methodologies ~~gas~~may ~~emitting~~limit ~~energy~~our ~~sources~~ability ~~such~~to asset ~~solar~~rates ~~and~~based ~~wind,~~on our ~~products~~actual ~~would~~costs, ~~become~~may ~~less~~delay ~~desirable~~the inuse ~~the~~of ~~market~~rates ~~with~~that reflect ~~more~~increased ~~stringent~~costs, ~~limitations~~and onmay ~~greenhouse~~subject ~~gas~~us ~~emissions.~~to Wepotentially ~~cannot~~burdensome ~~predict~~and ~~with~~expensive ~~any~~operational, ~~certainty~~reporting atand ~~this~~other ~~time~~requirements. ~~how~~Any ~~these~~of ~~possibilities~~the ~~may~~foregoing could adversely affect our business, results of operations and financial condition.

AIf ~~change~~our intariff ~~the~~rates ~~jurisdictional~~are ~~characterization~~successfully ~~of some of our assets by federal~~challenged, ~~state~~we orcould ~~local~~be ~~regulatory~~required ~~agencies~~to orreduce ~~a change in policy by those agencies may result in increased regulation of~~ our ~~assets~~tariff rates, which ~~may~~would ~~cause~~reduce our revenues ~~to decline and operating expenses to increase~~.

~~Our~~Shippers ~~operations~~on ~~are~~our ~~generally~~pipelines ~~exempt~~are ~~from~~free ~~regulation~~to ~~by the FERC~~challenge, ~~but~~or ~~FERC~~to ~~regulations~~cause ~~still~~other ~~affect~~parties ~~our~~to ~~non-FERC~~challenge ~~jurisdictional~~or ~~businesses~~assist ~~and~~others ~~the~~in ~~markets~~challenging, ~~for~~our ~~products~~existing ~~derived~~or ~~from~~proposed ~~these~~tariff ~~businesses~~rates. ~~The~~If ~~FERC~~any ~~issued~~party ~~Order~~successfully ~~704,~~challenges ~~which~~our ~~requires~~tariff ~~certain~~rates, ~~participants in~~ the ~~natural~~effect ~~gas~~would ~~market,~~be ~~including interstate and intrastate pipelines, natural gas gatherers, natural gas marketers, and natural gas processors that engage in a minimum level of natural gas sales or purchases,~~ to ~~submit~~reduce ~~annual reports regarding those transactions~~revenues.

OtherOur FERCsales regulationsof mayoil indirectly impact our businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and marketany centerhedging promotion,activities mayrelated indirectlyto affectsuch theenergy intrastate natural gas market. In recent yearscommodities, theexpose FERCus has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot be assured that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to transportationpotential capacity.regulatory risks.

~~Section 1(b)~~FERC, ofthe FTC and the ~~NGA~~CFTC ~~exempts~~hold ~~natural~~statutory ~~gas~~authority ~~gathering~~to ~~facilities~~regulate ~~from~~certain ~~regulation~~segments byof the ~~FERC~~physical asand afutures ~~natural~~energy ~~gas~~commodities ~~company.~~markets Werelevant ~~believe~~to ~~that~~ our ~~natural~~business. ~~gas~~These ~~gathering~~agencies ~~facilities~~have ~~meet~~imposed ~~the~~broad ~~traditional~~regulations ~~tests~~prohibiting ~~the~~fraud ~~FERC~~and ~~has~~manipulation ~~used~~of tosuch ~~establish~~markets. aWith ~~pipeline’s~~regard ~~status~~to asour aphysical ~~gatherer~~sales ~~not~~of ~~subject~~oil toand ~~regulation as a~~ natural gas, ~~company.~~and ~~However,~~any ~~the~~hedging ~~distinction~~activities ~~between~~related ~~FERC-regulated~~to ~~transmission~~these ~~facilities~~commodities, ~~and~~we ~~federally~~are ~~unregulated~~required ~~gathering~~to ~~facilities~~observe isand ~~the~~comply ~~subject~~with ofthese onanti-~~going~~fraud ~~litigation,~~and soanti-manipulation ~~the~~regulations. ~~classification~~Failure ~~and~~to ~~regulation~~comply ofwith ~~our~~such ~~gathering~~regulations, ~~facilities~~as ~~are~~interpreted ~~subject~~and toenforced, ~~change~~could ~~based~~materially onand ~~future~~adversely ~~determinations~~affect byour ~~the~~financial ~~FERC~~condition or ~~the~~results ~~courts~~of operations.

InWe addition,have theidentified courtsmaterial haveweaknesses determinedin thatour certaininternal pipelinescontrols that, wouldif otherwisenot beproperly subject to the ICA are exempt from regulation by the FERC under the ICA as proprietary lines. The classification of a line as a proprietary line is a fact-based determination subject to FERC and court review. Accordinglycorrected, thecould classificationresult andin regulationmaterial ofmisstatements somein of our gatheringfinancial facilities and transportation pipelines may be subject to change based on future determinations by the FERC or the courtsstatements.

~~The~~Our ~~former~~management ~~BOEMRE~~has ~~communicated~~identified ~~that~~material itweaknesses ~~would~~in ~~commence~~our ~~more~~internal ~~stringent~~control ~~enforcement~~over offinancial ~~requirements~~reporting toas ~~decommission~~of ~~facilities~~June ~~that~~30, ~~pose~~2015. aFurther, ~~hazard~~we tohave ~~safety~~determined orthat ~~the~~control ~~environment~~deficiencies orexisted ~~are~~with ~~not~~respect ~~useful~~to ~~for~~certain ~~lease~~aspects ~~operations and are not capable~~ of ~~oil~~our ~~and~~historical ~~natural~~financial ~~gas~~reporting ~~production~~subsequent into ~~“paying~~the ~~quantities.” Historically~~Merger, ~~the~~and ~~former~~accordingly, ~~BOEMRE~~we ~~granted~~have ~~approval~~concluded tothat ~~operators~~our toreports ~~maintain~~subsequent ~~such facilities in order~~ to ~~conduct~~the ~~other~~Merger ~~future~~on ~~activities.~~disclosure ~~However,~~controls weand ~~expect~~procedures ~~that~~may ~~this~~not ~~practice~~have ~~will~~been becorrect ~~more~~and ~~limited~~reports insubsequent to the ~~future.~~Merger ~~The~~on ~~former~~internal ~~BOEMRE~~control ~~stated~~over ~~that~~financial ~~these~~reporting ~~measures~~and ~~were~~changes in ~~response~~internal tocontrol ~~recent~~over ~~hurricane~~financial ~~seasons~~reporting inmay ~~which~~have ~~idle~~been ~~structures were damaged or destroyed~~incorrect. InA ~~2011,~~material weweakness ~~responded~~is to a ~~BOEMRE~~deficiency, ~~written~~or ~~request to review and evaluate our inventory~~ combination of ~~non-producing~~deficiencies ~~wells~~in ~~and~~internal ~~facilities~~controls toover ~~determine~~financial ~~the~~reporting ~~future~~that ~~utility~~results ofin ~~these~~a ~~structures~~reasonable ~~and~~possibility ~~the~~that ~~level~~a ofmaterial ~~threat~~misstatement ~~posed to the environment and human safety in the event~~ of ~~a “catastrophic loss.” We periodically review~~ our ~~plans~~annual ~~with~~or ~~the~~interim ~~BSEE~~financial tostatements ~~perform~~will ~~wellbore~~not ~~plugging~~be ~~and~~prevented ~~abandonment~~or ~~and~~detected ~~decommissioning work~~ on ~~certain~~a ~~facilities~~timely ~~and structures in our East Bay field~~basis.

The BOEM, BSEE and other regulatory bodies, including those regulating the decommissioning of our pipelines and facilities under the jurisdiction of the state of Louisiana, may change their requirements or enforce requirements in a manner inconsistent with our expectations, which could materially increase the cost of such activities and/or accelerate the timing of cash expenditures and could have a material adverse effect on our financial position, results of operations and cash flows. 36

~~The~~TABLE ~~failure~~OF to comply with these rules and regulations can result in substantial penalties, including lease termination in the case of federal leases. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, though the impact of those requirements may vary significantly based on the nature and location of operations and related pipelines and facilities. CONTENTS

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 33 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.

~~Should~~In addition, we ~~fail~~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 ~~all~~the ~~applicable~~procedural ~~FERC~~requirements ~~administered~~of ~~statutes~~the Company’s Code of Business Conduct and Ethics. Upon learning of Mr. Schiller’s personal loans from affiliates of service providers, ~~rules~~our parent’s board of directors engaged independent legal counsel to conduct an internal investigation, ~~regulations~~with the assistance of outside forensic accountants, to review these loans and ~~orders~~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 ~~could~~have concluded this non-compliance to be ~~subject~~a material weakness in its control environment given the leadership position of this officer, the visibility and importance of his actions to ~~substantial~~the ~~penalties~~Company’s overall system of controls and ~~fines~~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.

~~Under~~If ~~the~~we ~~EPAct~~are of 2005, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation and disgorgement of profits associated with any violation. While our systems have traditionally not ~~been~~able ~~subject~~ to ~~full~~remedy ~~FERC regulation,~~ the ~~FERC’s~~control ~~civil~~deficiencies ~~penalty~~in ~~authority may apply to~~ a ~~broad~~timely ~~range of market participants that have not historically been subject to its regulations. In addition~~manner, ~~FERC~~we ~~has adopted regulations that~~ may ~~subject~~be ~~certain~~unable ~~of our otherwise non-FERC jurisdictional facilities~~ to ~~annual~~provide ~~reporting~~holders ~~requirements.~~of ~~Additional rules and regulations that impact~~ our ~~facilities~~securities ~~and~~with ~~operations may be considered or adopted by~~ the ~~FERC~~required ~~from~~financial ~~time~~information toin ~~time.~~a ~~Failure~~timely toand ~~comply~~reliable ~~with~~manner, ~~those~~either ~~regulations~~of inwhich ~~the future~~ could subject us to ~~civil~~litigation ~~penalty~~and ~~liability~~regulatory enforcement actions.

OurClimate saleschange legislation or regulations restricting emissions of oil“greenhouse andgases” naturalcould gas,result andin anyincreased hedgingoperating activitiescosts relatedand toreduced suchdemand energyfor commodities,the exposecrude usoil toand potentialnatural regulatorygas risks.that we produce.

The ~~FERC~~EPA has determined that emissions of carbon dioxide, ~~the~~methane ~~Federal~~and ~~Trade~~other ~~Commission~~“greenhouse gases” present an endangerment to public health and the ~~CFTC,~~environment ~~hold~~because ~~statutory~~emissions ~~authority~~of such gases are, according to ~~monitor~~the ~~certain~~EPA, ~~segments~~contributing to warming of the ~~physical~~earth’s atmosphere and ~~futures~~other ~~energy~~climatic ~~commodities~~changes. ~~markets~~Based ~~relevant~~on tothese ~~our~~findings, ~~business.~~the ~~These~~EPA ~~agencies~~has ~~have~~begun ~~imposed~~adopting ~~broad~~and implementing regulations ~~prohibiting~~to ~~fraud~~restrict ~~and~~emissions ~~manipulation~~of greenhouse gases under existing provisions of ~~such~~the ~~markets.~~federal ~~With~~Clean ~~regard~~Air toAct ~~our~~(“CAA”). ~~physical~~Among ~~sales~~the ofEPA’s ~~oil~~rules ~~and~~regulating ~~natural~~greenhouse gas, ~~and~~emissions ~~any~~under ~~hedging~~the ~~activities~~CAA, ~~related~~one torequires ~~these~~a ~~energy~~reduction ~~commodities,~~in weemissions ~~are~~of ~~required~~greenhouse gases tofrom ~~observe~~motor ~~the~~vehicles ~~market-related~~and ~~regulations~~requires ~~enforced~~preconstruction byand ~~these~~operating ~~agencies,~~permits ~~which~~for ~~hold~~certain ~~substantial~~large ~~enforcement~~stationary ~~authority~~sources of such emissions. ~~Failure~~The toEPA ~~comply~~has ~~with~~also ~~such~~adopted ~~regulations,~~rules asrequiring ~~interpreted~~the monitoring and ~~enforced,~~reporting ~~could~~of ~~materially~~greenhouse ~~and~~gas ~~adversely~~emissions ~~affect~~from ~~our~~specified ~~financial~~greenhouse ~~condition~~gas oremission ~~results~~sources ofin ~~operations.~~the United States, including petroleum refineries

The enactment of derivatives legislation by Congress could have an adverse impact on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. 37

~~The~~TABLE ~~Dodd-Frank~~OF Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. The CFTC has finalized a number of regulations under the Dodd-Frank Act, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant.” The Dodd-Frank Act and the CFTC rules also will require us, in connection with certain derivative activities, to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements although these regulations are not finalized and their application to us is uncertain at this time. The CFTC, as part of its rulemaking under the Dodd-Frank Act, has also issued rules to impose position limits on certain futures and option contracts, and swaps which are the economic equivalent thereof. The subject of the proposed position limit rules includes parts of the energy market; however, the impact of these rules is uncertain at this time as the initial rules published by the CFTC were vacated by a court following litigation, and a new version of proposed rules has only recently been proposed by the CFTC and is still open for public comment until February 2014. Other regulations also remain to be finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and the CFTC rules on us and the timing of such effects. The Dodd-Frank Act also may require the 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 Dodd-Frank Act and any new regulations could significantly 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 Dodd-Frank Act and regulations implementing the Dodd-Frank Act, 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 Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing 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. CONTENTS

~~The~~and ~~proposed~~certain ~~United~~onshore ~~States~~oil ~~federal~~and ~~budget~~natural ~~for~~gas ~~fiscal~~production ~~year~~facilities. ~~2014~~In ~~may~~addition, ~~include~~in ~~certain~~January ~~provisions that~~2015, ifthe ~~passed~~Obama asAdministration ~~originally~~announced ~~submitted,~~its ~~will~~goal ~~have~~to anreduce ~~adverse~~methane ~~effect~~emissions onfrom ~~our~~the ~~financial~~oil ~~position,~~and ~~results~~gas sector by 40% to 45% from 2012 emission levels by 2025. As part of ~~operations~~this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and ~~cash~~a ~~flows~~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.

ToIn ~~date~~addition, the ~~Office~~U.S. ofCongress ~~Management~~has ~~and~~from ~~Budget~~time ~~has~~to ~~not~~time ~~released~~considered aadopting ~~summary~~legislation ofto ~~the~~reduce ~~proposed~~emissions ~~United~~of ~~States~~greenhouse ~~federal~~gases ~~budget~~and ~~for~~almost ~~fiscal~~one-half ~~year~~of ~~2014.~~the ~~When~~states ~~released,~~have italready istaken ~~anticipated~~legal ~~that~~measures asto areduce ~~result~~emissions of ~~possible~~greenhouse ~~significant~~gases ~~deficit~~primarily ~~reduction~~through orthe ~~comprehensive~~planned ~~tax~~development ~~reform~~of ~~measures~~greenhouse ~~currently~~gas ~~under~~emission ~~consideration~~inventories ~~the~~and/or ~~proposed~~regional ~~budget~~greenhouse ~~may~~gas ~~repeal~~cap ~~many~~and ~~tax~~trade ~~incentives~~programs. ~~and~~Most ~~deductions~~of ~~that~~these ~~are~~cap ~~currently~~and ~~used~~trade byprograms ~~United~~work ~~States~~by ~~oil~~requiring ~~and~~major ~~gas~~sources ~~companies~~of ~~and~~emissions, ~~impose~~such ~~new~~as ~~taxes.~~electric ~~The~~power ~~provisions~~plants, ~~include~~or ~~elimination~~major producers of ~~the~~fuels, ~~ability~~such toas ~~fully~~refineries ~~deduct~~and ~~intangible~~gas ~~drilling~~processing ~~costs~~plants, into ~~the~~acquire ~~year~~and ~~incurred,~~surrender ~~increases~~emission inallowances ~~the~~that ~~taxation~~correspond ofto ~~foreign~~their ~~source~~annual emissions ~~income,~~of ~~repeal~~greenhouse ofgases. ~~the~~The ~~manufacturing~~number ~~tax~~of ~~deduction~~allowances available for ~~oil~~purchase ~~and~~is ~~natural~~reduced ~~gas~~each ~~companies~~year ~~and~~in an ~~increase~~effort into achieve the ~~geological~~overall ~~and~~greenhouse ~~geophysical~~gas ~~amortization~~emission ~~period~~reduction ~~for independent producers~~goal. ~~Should~~As ~~some~~the ornumber ~~all~~ of ~~these~~emission ~~provisions~~allowances ~~become~~declines ~~law,~~each ~~our taxes will increase~~year, ~~potentially~~the ~~significantly,~~cost ~~which~~or ~~would~~value ~~have~~of asuch ~~negative~~allowances ~~impact~~is onexpected ~~our~~to ~~net~~escalate ~~income and cash flows~~significantly. ~~This could~~

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 34 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.

alsoThe causeadoption usof tofinancial reducereform ourlegislation drillingby activitiesCongress incould thehave Unitedan States.adverse Sinceeffect noneon ofour theseability proposalsto haveuse yetderivative instruments to bereduce votedthe oneffect orof becomecommodity lawprice, weinterest dorate notand knowother therisks ultimateassociated impactwith these proposed changes may have on our business.

~~Cyber~~Congress ~~attacks~~adopted ~~targeting~~comprehensive ~~systems~~financial reform legislation that establishes federal oversight and ~~infrastructure~~regulation ~~used~~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 ~~oil~~CFTC, the SEC and ~~gas~~other ~~industry~~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 ~~impact~~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

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. We have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. Although historically we have not incurred material expenditures for protective measures related to potential cyber attacks, as cyber attacks 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 vulnerabilities to cyber attacks. 38

~~Item 1B.Unresolved~~TABLE ~~Staff~~OF ~~Comments~~ CONTENTS

~~None~~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.

Item 2.PropertiesCyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.

The ~~information~~oil ~~contained~~and ingas ~~Part~~industry Ihas become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, ~~Item 1~~development and production activities. For example, ~~“Business”~~software ofprograms ~~this~~are ~~Annual~~used ~~Report~~to isinterpret ~~incorporated~~seismic ~~herein~~data, bymanage ~~reference~~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.

~~Item 3~~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.~~Legal~~ ~~Proceedings~~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.

~~The~~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 ~~contained~~, corrupting data, or causing operational disruption, or result in ~~Note~~denial-of-service 13on websites. Certain countries, ~~“Commitments~~including China, Russia and ~~Contingencies”~~Iran, inare ~~the~~believed ~~consolidated~~to ~~financial~~possess ~~statements~~cyber inwarfare ~~Part~~capabilities ~~II,~~and ~~Item 8~~are ofcredited ~~this~~with ~~Annual~~attacks ~~Report~~on isAmerican ~~incorporated~~companies ~~herein~~and bygovernment ~~reference~~agencies. SCADA-based systems are potentially more vulnerable to cyber-attacks due to the increased number of connections with office networks and the internet.

~~Item 4~~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. ~~Mine~~In ~~Safety~~addition, ~~Disclosures~~ certain cyber incidents, such as surveillance, may remain undetected for an extended period.

~~Not~~A ~~applicable.~~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:

~~PART II~~• unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

~~Item 5.Market~~• ~~for~~data ~~Registrant’s~~corruption, ~~Common~~communication ~~Equity~~interruption, ~~Related~~or ~~Stockholder~~other ~~Matters~~operational ~~and~~disruption ~~Issuer~~during ~~Purchases~~drilling ofactivities ~~Equity~~could ~~Securities~~result in a dry hole cost or even drilling incidents;

~~Our~~• ~~common~~data ~~stock~~corruption isor ~~listed~~operational ondisruption ~~the New York Stock Exchange (“NYSE”) under the symbol “EPL.” The following table sets forth, for the periods indicated, the range~~ of ~~the~~production ~~high~~infrastructure ~~and~~could ~~low~~result ~~sales~~in ~~prices~~loss of ~~our~~production, ~~common~~or ~~stock~~accidental ~~as reported by the NYSE.~~ discharge;

	High	Low
	($)	($)
2012
First Quarter	18.49	14.72
Second Quarter	17.53	14.56
Third Quarter	21.99	16.01
Fourth Quarter	23.28	19.31
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 (through February 21, 2014)	31.26	25.18

•

a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major development projects, effectively delaying the start of cash flows from the project;

On• ~~February 21,~~a ~~2014,~~cyber-attack ~~the~~on ~~last~~a ~~reported~~third ~~sales~~party ~~price~~gathering ofor ~~our~~pipeline ~~common~~service ~~stock~~provider oncould ~~the~~prevent ~~NYSE~~us ~~was~~from ~~$29.47~~marketing ~~per~~our ~~share.~~production, resulting in a loss of revenues;

As• ofa ~~February 21,~~cyber-attack ~~2014,~~involving ~~there~~commodities ~~were~~exchanges ~~approximately~~or ~~176 holders~~financial ofinstitutions ~~record~~could ofslow or halt commodities trading, thus preventing us from marketing our ~~common~~production ~~stock.~~or engaging in hedging activities, resulting in a loss of revenues;

35 39

WeTABLE ~~have~~OF not paid cash dividends in the past on our common stock. The covenants in certain debt instruments to which we are a party, including our Senior Credit Facility and 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. CONTENTS

~~Securities~~• ~~Authorized~~a cyber-attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for ~~Issuance~~our ~~under~~production, ~~Equity~~lower ~~Compensation~~natural ~~Plans~~gas prices, and reduced revenues;

~~The~~• ~~following~~a ~~table~~cyber-attack ~~provides~~on ~~information~~a ascommunications ofnetwork ~~December 31,~~or ~~2013~~power ~~with~~grid ~~respect~~could tocause ~~compensation~~operational ~~plans~~disruption ~~under~~resulting ~~which~~in ~~our~~loss ~~equity~~of ~~securities are authorized for issuance.~~ revenues;

Plan Category	Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights (1)		Weighted Average Exercise Price of Outstanding Options, Warrants and Rights (2)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans(3)
Equity compensation plans approved by stockholders (4)		1,088,382	$	22.56		1,184,322
Equity compensation plans not approved by stockholders (5)		809,286	$	13.35		-
Total		1,897,668	$	17.76		1,184,322

•

a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

~~(1)Comprised~~• ofbusiness ~~1,453,173~~interruptions ~~shares~~could ~~subject~~result toin ~~issuance~~expensive ~~upon~~remediation ~~the~~efforts, ~~exercise~~distraction of ~~options~~management, and ~~444,495~~damage ~~shares~~to ~~which~~our ~~will vest upon the lapsing of restrictions associated with restricted share awards~~reputation.

~~(2)Restricted~~Although ~~share~~to ~~awards~~date dowe have not ~~have~~experienced anany ~~exercise~~losses ~~price;~~relating ~~therefore~~to cyber-attacks, ~~this~~there ~~only~~can ~~reflects~~be no assurance that we will not suffer such losses in the ~~weighted-average~~future. ~~exercise~~As ~~price~~cyber ofthreats ~~options~~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.

(3)TheseCertain sharesU.S. arefederal availableincome fortax futuredeductions issuancecurrently underavailable thewith 2009respect Longto Termoil Incentiveand Plan,gas asexploration amended,and indevelopment themay formbe ofeliminated options,as appreciationa rights,result restrictedof shares,future deferred shares, bonus stock and performance shares, units or restricted stock unitslegislation.

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 (41)At ~~our~~the ~~2011~~repeal of the percentage depletion allowance for oil and ~~2013~~natural ~~annual~~gas ~~meetings~~properties, (2) the elimination of ~~stockholders,~~current ~~our~~deductions ~~stockholders~~for ~~approved~~intangible ~~increases~~drilling inand development costs, (3) the ~~number~~elimination of ~~shares~~the ~~authorized~~deduction for ~~issuance~~certain ~~under~~domestic production activities, and (4) an extension of the amortization ~~2009~~period ~~Long~~for ~~Term~~certain ~~Incentive~~geological ~~Plan~~and ~~from~~geophysical 1expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and,~~237~~ if enacted,~~000~~ ~~shares~~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 3oil and natural gas exploration and development,~~574~~ and any such changes could have an adverse effect on our financial position,~~000~~ ~~shares~~results of operations and cash flows.

(5)TheItem form of the 2009 Long Term Incentive Plan was filed with the supplement to our plan of reorganization and approved by the United States Bankruptcy Court for the Southern District of Texas prior to our emergence from Chapter 11 reorganization on September 21, 20091B. Accordingly,Unresolved noStaff stockholder approval was required, and none was sought or obtained. Comments

~~See Note 12 “Employee Benefit Plans” of the consolidated financial statements in Part II, Item 8 of this Annual Report for further information regarding the material features of the above plan~~None.

36 Item 2. Properties

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

ThisItem information is being “furnished” to the SEC and is not deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C under the Exchange Act or to the liabilities of Section 18 of the Exchange Act, and will not be deemed to be incorporated by reference into any filings we make under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent we specifically incorporate it be reference into such a filing3. Legal Proceedings

The ~~following~~information ~~graph~~contained ~~compares the cumulative total shareholder return on our common stock relative to the cumulative total returns of (i) the Russell 2000 index, (ii) our previous peer group, which was used~~ in ~~2012,~~Note ~~and includes: ATP Oil & Gas Corporation~~14, ~~Energy~~“Commitments ~~XXI (Bermuda) Limited, McMoRan Exploration Company, Stone Energy Corporation~~ and ~~W&T~~Contingencies” ~~Offshore,~~in ~~Inc. (~~the ~~“Old~~consolidated ~~Peer~~financial ~~Group”)~~statements ~~and~~in ~~(iii)~~Part ~~our new peer group~~II, ~~which~~Item is8 ~~a customized peer group~~ of ~~independent~~this ~~oil~~Form and natural gas exploration and production companies and includes: Contango Oil & Gas Company; Energy XXI (Bermuda) Limited; PetroQuest Energy, Inc.; Stone Energy Corporation; Swift Energy Corporation and W&T Offshore, Inc. (the “New Peer Group”). We modified our peer group to remove ATP Oil & Gas Corporation, which recently filed for Chapter 11 bankruptcy protection and McMoRan Exploration Company, which was acquired in early 2013 by Freeport10-~~McMoran~~K ~~Copper & Gold, a company which~~ is ~~more~~incorporated ~~diversified~~herein ~~than~~by ~~our company~~reference. ~~Our New Peer Group consists of companies which we believe focus in a geographic area similar to ours and which we believe analysts would be more likely to compare us with for investment purposes.~~

TheItem graph tracks the performance of a $100 investment in our common stock, the New Peer Group, the Old Peer Group and the Russell 2000 index (with reinvestment of all dividends) from September 30, 2009, the end of the first month in which we emerged from Chapter 11 bankruptcy proceedings, through December 31, 20134. Because theMine valueSafety of our old common stock bears no relation to the value of our existing common stock, the graph below reflects only our new common stock. The historic price performance is not necessarily indicative of future stock performance. Disclosures

	9/30/09	12/31/09	12/31/10	12/31/11	12/31/12	12/31/13
EPL Oil & Gas, Inc	100.00	114.61	199.20	195.71	302.28	382.04
Russell 2000	100.00	103.87	131.77	126.27	146.91	203.95
Old Peer Group	100.00	116.30	176.75	118.25	111.46	131.82
New Peer Group	100.00	103.07	159.38	167.42	136.09	143.26

Not applicable.

37 40

~~Item 6.Selected~~TABLE ~~Financial~~OF ~~Data~~ CONTENTS

ThePART following table shows selected financial data derived from our consolidated financial statements, which are set forth in Part II, Item 8, “Financial Statements and Supplementary Data” of this Annual Report. The data should be read in conjunction with Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report.

	Successor Company										Predecessor Company (1)
	Year Ended December 31, 2013		Year Ended December 31, 2012		Year Ended December 31, 2011		Year Ended December 31, 2010		Period from October 1, 2009 through December 31, 2009		Period from January 1, 2009 through September 30, 2009
		(In thousands, except per share data)
Statement of Operations Data:
Revenue	$	693,038	$	423,633	$	348,327	$	239,909	$	56,750	$	134,885
Income (loss) from operations (2)		219,591		130,447		67,126		7,309		(4,523)		(51,323)
Net income (loss)		85,274		58,810		26,611		(8,468)		(21,012)		(36,114)
Basic earnings (loss) per common share	$	2.18	$	1.50	$	0.66	$	(0.21)	$	(0.53)	$	(1.12)
Diluted earnings (loss) per common share	$	2.15	$	1.50	$	0.66	$	(0.21)	$	(0.53)	$	(1.12)

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

	Successor Company As of December 31,
	2013		2012		2011		2010		2009
	(In thousands)
Balance Sheet Data:
Total assets (2)		1,857,831	$	1,705,627	$	915,220	$	626,906	$	709,228
Long-term debt, excluding current maturities(2) (3)		627,355		689,911		204,390		-		58,590
Stockholders’ equity		629,213		545,973		491,045		473,116		480,087
Cash dividends per common share		-		-		-		-		-

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.

~~(1)In~~Prior ~~connection~~to ~~with~~the Merger, our ~~emergence~~common ~~from~~stock ~~Chapter~~was 11listed ~~reorganization,~~on wethe ~~adopted~~NYSE ~~fresh-start~~under ~~accounting~~the assymbol ~~of September 30, 2009~~“EPL.” ~~Fresh-start~~The ~~accounting~~following istable ~~required~~sets ~~upon~~forth, afor ~~substantive change in control and requires that~~ the ~~reporting~~periods ~~entity~~indicated, ~~allocate~~ the ~~reorganization~~range ~~value~~ of the ~~Company~~high ~~to its assets~~ and ~~liabilities~~low insales ~~relation~~prices ~~to their fair values. Under the provisions~~ of ~~fresh-start~~our ~~accounting,~~common astock ~~new~~as ~~entity~~reported ~~has~~by ~~been~~the ~~deemed created for financial reporting purposes~~NYSE.

(2)During the year ended December 31, 2012, we acquired the Hilcorp Properties and the ST41 Interests. In connection with the Hilcorp Acquisition, we issued $300.0 million in aggregate principal amount of our 8.25% Senior Notes. During the year ended December 31, 2011, we acquired the ASOP Properties and Main Pass Interests. In connection with the ASOP Acquisition, we issued $210.0 million in aggregate principal amount of our 8.25% Senior Notes.


	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

~~(3)At~~On ~~December 31~~June 3, ~~2013~~2014, ~~2012~~the ~~and~~last ~~2011,~~reported ~~none~~sales price of our ~~debt~~common ~~was~~stock ~~classified~~on asthe ~~current.~~NYSE ~~At December 31, 2010, we had no borrowings outstanding. At December 31, 2009 long-term debt classified as current~~ was $1837.873 ~~million~~per share.

~~Item 7~~We have not paid cash dividends in the past on our common stock.~~Management’s~~ ~~Discussion~~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 ~~Analysis~~conditions ofon ~~Financial~~our ~~Condition~~ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and ~~Results~~other factors determined by our board of ~~Operations~~ directors.

~~Overview~~Item 6. Selected Financial Data

WeNot ~~were~~applicable ~~incorporated~~due asto areduced ~~Delaware~~disclosure ~~corporation~~format inallowed ~~January~~for ~~1998~~certain ~~and~~wholly-owned ~~operate~~subsidiaries inpursuant ato ~~single~~General ~~segment~~Instruction as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the U.S. Gulf of Mexico shelf focusing on state and federal waters offshore Louisiana, which we consider our core area. We have focused on acquiring and developing assets in this region, as it offers I(1)(a) ~~balanced~~ and ~~expansive~~(b) ~~array~~ of ~~existing~~Form ~~and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations~~10-K. ~~As of December 31, 2013, we had estimated proved reserves of 80.4 Mmboe, of which 64% were oil and 71% were proved developed. Of these proved developed reserves, 69% were oil reserves.~~

38 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

~~Recent~~The ~~Events~~ 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.

OnRestatement January 15, 2014, we completed the Nexen Acquisition for $70.4 million, subject to customary adjustments to reflect the September 1, 2013, economic effective date. The assets we acquired include five leases in the Eugene Island 258/259 field—namely blocks 254, 255, 257, 258, and 259 (the “EI Interests”). The EI Interests are currently producing approximately 900 net Boe per day, about 95% of whichPreviously isIssued oil. EstimatedConsolidated provedFinancial reserves as of the September 1, 2013 effective date consisted of approximately 2.6 Mmboe of proved developed producing reserves, about 91% of which were oil. The estimated asset retirement obligation to be assumed and recorded on our balance sheet as a result of the Nexen Acquisition is expected to total approximately $27.1 million. Statements

~~The~~Management’s ~~Nexen~~Discussion ~~Acquisition~~and ~~was~~Analysis ~~financed~~of ~~with~~Financial ~~borrowings~~Condition ~~under~~and ~~our~~Results ~~Senior~~of ~~Credit~~Operations ~~Facility. In~~have ~~January~~been ~~2014,~~updated ~~our~~to ~~lenders~~reflect ~~approved~~the aeffects ~~$50.0~~of ~~million~~the ~~increase~~restatement described in ~~our~~Note ~~borrowing~~17 — Restatement ~~base~~of ~~under~~Previously Issued Consolidated Financial Statements of Notes to Consolidated Financial Statements in this Form 10-K. We have also included our ~~Senior~~restated ~~Credit~~financial ~~Facility,~~statements ~~increasing~~for the three unaudited quarters of fiscal 2015 following our ~~borrowing~~fiscal ~~base~~year ~~from~~2015 ~~$425.0~~financial ~~million~~statements toin ~~$475.0~~Item ~~million. See~~8, “~~—Liquidity~~Financial Statements and ~~Capital~~Supplementary ~~Resources—Senior~~Data” ~~Credit~~in ~~Facility”~~this Form 10-K. In addition, we have included a discussion of restated revenues, related costs and income tax expense for ~~more~~the ~~information~~three ~~regarding~~unaudited quarters of 2015 following the discussion of our ~~Senior~~results ~~Credit~~of ~~Facility~~operations for our year ended June 30, 2015 compared to the year ended December 31, 2013.

In September and October 2013, we negotiated agreements totaling approximately $45 million with seismic companies to acquire 3D seismic licenses over our core areas. These agreements include a commitment to acquire area-wide data licenses for seismic acquisitions that will be performed by the seismic company during 2014, 2015 and 2016 covering a minimum of 200 blocks, or approximately one million acres, within the shallow water Gulf of Mexico covering our core asset base. 41

~~2013~~TABLE ~~Acquisitions~~OF ~~and Dispositions~~ CONTENTS

OnIn ~~April~~connection 2,with ~~2013~~preparing this Form 10-K, we ~~sold~~determined ~~certain~~that ~~shallow~~the ~~water~~contemporaneous ~~Gulf~~formal documentation that we had prepared subsequent to the Merger to support our designations of ~~Mexico~~derivative ~~shelf~~financial instruments as cash flow hedges in connection with our crude oil and natural gas ~~interests~~hedging ~~located~~program ~~within~~did not meet the ~~non-operated~~technical ~~Bay~~requirements ~~Marchand~~to ~~field~~qualify ~~(the~~for ~~“BM~~cash ~~Interests”)~~flow tohedge ~~the~~accounting ~~property~~treatment ~~operator~~in ~~for~~accordance ~~$51.5~~with ~~million~~ASC inTopic ~~cash~~815, Derivatives and Hedging. The primary reason for this determination was that the ~~buyer’s~~formal ~~assumption~~hedge documentation lacked specificity of ~~liabilities~~the ~~recorded~~hedged onitems ~~our~~and, ~~balance~~therefore, ~~sheet~~the ofdesignations ~~$11~~failed to meet hedge documentation requirements for cash flow hedge accounting treatment.3 ~~million~~Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in ~~total~~our ~~consideration~~consolidated statements of ~~$62~~operations as a component of earnings.8 ~~million,~~Under ~~subject~~the tocash ~~customary~~flow ~~adjustments~~hedge toaccounting ~~reflect~~treatment ~~the~~applied ~~January~~subsequent 1to the Merger, ~~2013~~we ~~economic~~had ~~effective~~recorded ~~date. Our~~unrealized ~~results~~gains ~~for~~or losses resulting from changes in the ~~year~~fair ~~ended~~value ~~December~~of 31our derivative financial instruments, ~~2013~~net ~~reflect~~of athe ~~pre-~~related tax ~~gain~~impact, ofin ~~$28.1~~accumulated ~~million~~other ~~from~~comprehensive ~~this~~income ~~sale. See~~or ~~“—Liquidity~~loss ~~and~~until ~~Capital~~the ~~Resources—Acquisitions~~production ~~and~~month ~~Dispositions”~~when inthe ~~this~~associated ~~Item~~hedge 2contracts ~~for~~were ~~more~~settled, ~~information~~at ~~regarding~~which time gains or losses associated with the ~~use~~settled ofcontracts ~~proceeds~~were ~~from~~reclassified ~~this~~to ~~sale~~revenues.

OnThis ~~September 26~~restatement, ~~2013~~which impacts periods subsequent to the Merger, weprimarily ~~acquired~~reflects the ~~WD29~~recognition ~~Interests~~of ~~for~~gains ~~$21.8~~and ~~million~~losses on derivative financial instruments previously included in ~~cash,~~accumulated ~~subject~~other comprehensive income (loss) to ~~customary~~gain ~~adjustments~~(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 ~~reflect~~gain an(loss) ~~economic~~on ~~effective~~derivative ~~date~~financial instruments as a result of ~~January 1~~not qualifying for cash flow hedge accounting treatment as described above. For the quarters ending December 31, ~~2013~~2014 (and March 31, 2015, the ~~“WD29~~restatement ~~Acquisition”).~~also reflects Weresulting ~~estimate~~adjustments ~~that~~to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the ~~proved~~previous ~~reserves~~inclusion asof the value of the ~~January 1~~cash flow hedges in our full cost ceiling test, ~~2013~~which ~~economic~~is ~~effective~~only ~~date~~permitted ~~totaled~~if ~~approximately~~the 0derivative instruments qualify for cash flow hedge accounting.7 ~~Mmboe~~Additionally, ofresulting ~~which~~adjustments ~~95%~~to ~~were~~deferred ~~oil~~income taxes and ~~58%~~income ~~were~~tax ~~proved~~expense ~~developed~~(benefit) ~~reserves~~are also reflected in the restatement. ~~The~~While ~~WD29~~these ~~Acquisition~~non-cash ~~was~~adjustments ~~funded~~impact ~~with~~revenues aand ~~portion~~net ofincome ~~the~~(loss) ~~proceeds~~for ~~from~~each period, as well as total stockholders’ equity, these adjustments do not impact the ~~sale~~economics of the BMhedge ~~Interests~~transactions ~~described~~nor ~~above~~do they affect our liquidity.

On March 20, 2013, we were the high bidder on five leases at the Central Gulf of Mexico Lease Sale 227. The five high bid lease blocks cover a total of 13,892 acres on a gross and net basis and are all located in the shallow Gulf of Mexico within our core area of operations. Our share of the high bids totaled approximately $2.1 million. We have been awarded all five of the leases. Overview

~~2012~~We ~~Acquisitions~~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 ~~October~~June 313, ~~2012~~2014, weEnergy ~~acquired~~XXI, ~~the~~EGC, ~~Hilcorp~~Merger ~~Properties~~Sub, ~~for~~and ~~$550.0~~EPL, ~~million~~completed inthe ~~cash,~~transactions ~~subject~~contemplated toby ~~customary~~the ~~adjustments~~Merger toAgreement, ~~reflect~~by anand ~~economic~~among ~~effective~~Energy ~~date~~XXI, ofEGC, ~~July~~Merger 1Sub, ~~2012. As~~and ofEPL, ~~December~~pursuant ~~31,~~to ~~2012,~~which ~~the~~Merger ~~Hilcorp~~Sub ~~Properties~~was ~~had~~merged ~~estimated~~with ~~proved~~and ~~reserves~~into ofEPL ~~approximately~~with ~~37.2~~EPL ~~Mmboe,~~continuing ofas ~~which~~the ~~49%~~surviving ~~were~~corporation. ~~oil~~Pursuant ~~and~~to ~~58%~~the ~~were~~Merger ~~proved~~Agreement, ~~developed~~at ~~reserves.~~the ~~The~~effective ~~Hilcorp~~time ~~Properties~~of ~~included~~the Merger, the ~~three~~issued ~~core~~and ~~producing~~outstanding ~~complexes~~shares of ~~the~~EPL ~~Ship~~common ~~Shoal~~stock ~~208~~were converted, ~~South~~in ~~Pass~~the 78aggregate, ~~and~~into ~~South~~the ~~Marsh~~Merger ~~Island~~Consideration ~~239~~consisting ~~areas~~of ~~and~~approximately ~~related~~65% ~~gathering~~in ~~lines~~cash ~~which~~and ~~are~~35% ~~described~~ in ~~Part~~shares I,of ~~Item~~Energy 1,XXI ~~“Business~~Common ~~– Properties~~Stock.”

~~The~~As ~~Hilcorp~~a ~~Acquisition~~result ~~was~~of ~~financed~~the ~~with cash on hand~~Merger, the ~~net~~future ~~proceeds~~strategy ~~from~~of the ~~sale~~Company ofis ~~$300.0~~determined ~~million~~by inEnergy ~~aggregate~~XXI’s ~~principal~~Board ~~amount~~ of ~~our~~ 8Directors.~~25%~~ ~~senior~~For ~~notes due 2018 (~~the ~~“2012~~year ~~Senior~~ended ~~Notes”)~~June ~~and~~30, ~~borrowings~~2015, ~~under~~ our ~~Senior~~capital ~~Credit~~expenditures ~~Facility.~~totaled ~~The~~approximately ~~2012~~$271 ~~Senior~~million, ~~Notes were~~of ~~offered~~which inapproximately a$186 ~~private~~million ~~placement~~was ~~only~~spent toon ~~qualified~~development ~~institutional buyers under Rule 144A promulgated under the Securities Act~~ of ~~1933,~~core asproperties ~~amended~~and ~~(the~~$27 ~~“Securities~~million ~~Act”),~~on orexploration ~~to persons outside~~ of ~~the~~core ~~United~~properties ~~States~~and in$58 ~~compliance~~million ~~with~~on ~~Regulation~~other ~~S promulgated under the Securities Act~~assets. ~~After~~ ~~deducting~~Our ~~the~~fiscal ~~initial~~year ~~purchasers’~~2016 ~~discount,~~capital webudget ~~realized~~is ~~net~~approximately ~~proceeds of~~ $~~289.5~~26 million~~. Also~~, onexcluding ~~October~~potential ~~31,~~capitalized ~~2012,~~general weand ~~obtained~~administrative anexpenses. ~~increase~~The inbudgeted ~~the~~capital ~~aggregate~~is ~~commitment~~allocated ~~under~~to ~~our~~development ~~Senior~~activities, ~~Credit~~which ~~Facility~~are ~~from~~geared ~~$250.0~~toward ~~million~~the toimprovement ~~$750.0~~of ~~million~~existing ~~under~~production, the ~~which~~continued wedevelopment ~~borrowed~~of ~~$205.0~~core ~~million~~fields, toand ~~fund~~the aperformance ~~portion~~ of ~~the~~necessary ~~purchase~~plugging, ~~price~~abandonment and ~~related~~other ~~expenses~~decommissioning ~~of the Hilcorp Acquisition~~activities.

In the June 20, 2012, Central Gulf of Mexico Lease Sale 216/222, we were the high bidder on six leases covering a total of 27,148 acres on a gross and net basis located in the shallow Gulf of Mexico shelf within our core area of operations. Our share of the high bids totaled approximately $7.0 million. Disposition

On ~~May 15~~June 30, ~~2012~~2015, we ~~acquired~~sold ~~the~~our ~~ST41~~interest ~~Interests for $32.4 million~~ in ~~cash,~~the ~~subject~~East toBay ~~customary~~field ~~adjustments~~ to ~~reflect~~Whitney anOil ~~economic~~& ~~effective~~Gas, ~~date~~LLC ofand ~~April 1,~~Trimont ~~2012~~Energy (~~the “ST41 Acquisition”~~NOW)., ~~Prior to the ST41 Acquisition~~LLC, wefor ~~owned~~cash aconsideration ~~60%~~of ~~working~~$21 ~~interest~~million, inplus the ~~properties,~~assumption ~~and~~of ~~W&T~~asset ~~owned~~retirement aobligations ~~40%~~totaling ~~working~~approximately ~~interest~~$55.1 Asmillion. aThe ~~result~~cash ofconsideration ~~the~~is ~~ST41~~payable ~~Acquisition,~~in wetwo ~~have~~installments ~~become~~with ~~the~~$5 ~~sole~~million ~~working~~received ~~interest~~at ~~owner~~closing ofand the ~~South~~remainder ~~Timbalier~~due 41on ~~field.~~or ~~The~~before ~~ST41~~October ~~Interests~~31, ~~had~~2015. ~~estimated~~We ~~proved~~retained ~~reserves~~a as5%

39 42

Filing Compare · EPL OIL & GAS, INC.