10-K 1 v413187_10k.htm 10-K

  

  

 

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



 

FORM 10-K



 

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

For the fiscal year ended June 30, 2015

or

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

For the transition period from          to         

Commission file number: 001-33628



 

Energy XXI Ltd

(Exact name of registrant as specified in its charter)



 

 
Bermuda   98-0499286
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

 
Canon’s Court, 22 Victoria Street,
PO Box HM 1179,
Hamilton HM EX, Bermuda
  N/A
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (441)-295-2244



 

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

 
Title of each class   Name of each exchange on which registered
Common Stock, par value $0.005 per share   NASDAQ Global Select Market

Securities registered pursuant to Section 12(g) of the Act: None



 

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

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

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

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

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

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

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

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

The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $224,982,321 based on the closing sale price of $3.26 per share as reported on The NASDAQ Global Select Market on December 31, 2014, the last business day of the registrant’s most recently completed second fiscal quarter.

The number of shares of the registrant’s common stock outstanding on September 18, 2015 was 94,966,655.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2015 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2015, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 


 
 

TABLE OF CONTENTS

TABLE OF CONTENTS

 
  Page
GLOSSARY OF TERMS     ii  
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS     i  
PART I
 

Item 1

Business

    3  

Item 1A

Risk Factors

    22  

Item 1B

Unresolved Staff Comments

    47  

Item 2

Properties

    47  

Item 3

Legal Proceedings

    48  

Item 4

Mine Safety Disclosures

    48  
PART II
 

Item 5

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

    49  

Item 6

Selected Financial Data

    51  

Item 7

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    55  

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

    84  

Item 8

Financial Statements and Supplementary Data

    87  

Item 9

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    287  

Item 9A

Controls and Procedures

    287  

Item 9B

Other Information

    289  
PART III
 

Item 10

Directors, Executive Officers and Corporate Governance

    289  

Item 11

Executive Compensation

    289  

Item 12

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    289  

Item 13

Certain Relationships and Related Transactions, and Director Independence

    289  

Item 14

Principal Accounting Fees and Services

    290  
PART IV
 

Item 15

Exhibits, Financial Statement Schedules

    290  
Signatures     296  

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GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this Annual Report on Form 10-K:

     
Bbls   Standard barrel containing 42 U.S. gallons   MMBbls   One million Bbls
Mcf   One thousand cubic feet   MMcf   One million cubic feet
Btu   One British thermal unit   MMBtu   One million Btu
BOE   Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil   MBOE   One thousand BOEs
DD&A   Depreciation, Depletion and Amortization   MMBOE   One million BOEs
Bcf   One billion cubic feet          

Call options are contracts giving the holder (purchaser) the right, but not the obligation, to buy (call) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and/or crude oil from a recently drilled or recompleted well.

Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploitation is drilling wells in areas proven to be productive.

Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well or a service well.

Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a)(8) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).

Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.

Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.

Gross acres or gross wells are the total acres or wells in which a working interest is owned.

Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.

Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.

Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the fractional working interest owned in the properties.

Oil includes crude oil, condensate and natural gas liquids.

Operating costs include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain wells and related equipment and facilities.

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Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.

Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a)(20) of Regulation S-X as promulgated by the SEC.

Productive well is an exploratory, development or extension well that is not a dry well.

Proved area refers to the part of a property to which proved reserves have been specifically attributed.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. For a complete definition of proved reserves, refer to Rule 4-10(a)(22) of Regulation S-X as promulgated by the SEC.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a)(3) of Regulation S-X as promulgated by the SEC.

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4-10(a)(4) of Regulation S-X as promulgated by the SEC.

Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).

Reserve acquisition cost The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.

Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover is the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.

Zone is a stratigraphic interval containing one or more reservoirs.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

our business strategy;
further or sustained declines in the prices we receive for our oil and gas production;
our future financial condition, results of operations, revenues, cash flows and expenses;
our future levels of indebtedness, liquidity and compliance with debt covenants;
our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations;
economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers;
uncertainties in estimating our oil and gas reserves and net present values of those reserves;
the need to take ceiling test impairments due to lower commodity prices;
hedging activities exposing us to pricing and counterparty risks;
replacing our oil and gas reserves;
geographic concentration of our assets;
uncertainties in exploring for and producing oil and gas, including exploitation, development, drilling and operating risks;
our ability to make acquisitions and to integrate acquisitions;
our ability to establish production on our acreage prior to the expiration of related leaseholds;
availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation;
disruption of operations and damages due to capsizing, collisions, hurricanes or tropical storms;
environmental risks;
availability, cost and adequacy of insurance coverage;
competition in the oil and gas industry;
our inability to retain and attract key personnel;
the effects of government regulation and permitting and other legal requirements;

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costs associated with perfecting title for mineral rights in some of our properties; and
weakness in our internal controls.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read (1) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-K, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (3) other public announcements we make from time to time.

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

EXPLANATORY NOTE — RESTATEMENT OF FINANCIAL INFORMATION

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

This Form 10-K for the year ended June 30, 2015 includes (1) a restated balance sheet as of June 30, 2014, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended June 30, 2014 and 2013, (3) restated quarterly consolidated financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, March 31, 2015 and 2014, (4) restated quarterly consolidated financial information for the quarter ended June 30, 2014, and (5) restated selected financial data for the years ended June 30, 2014, 2013, 2012, and 2011. See Item 6, “Selected Financial Data,” Item 8, “Financial Statements and Supplementary Data,” and Item 9A, “Controls and Procedures,” in Part II of this Form 10-K, including Notes 22 and 23 of the notes to the Consolidated Financial Statements, for more information concerning these restatements. The consolidated financial statements for prior periods presented in this report have been restated primarily to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) as gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling tests, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement.

We do not plan to amend previously filed reports in connection with the restatement. The consolidated financial statements that have been previously filed or otherwise reported for these periods are superseded by the information in this Form 10-K. Unless otherwise stated, all financial and accounting information contained in this Form 10-K is presented on a restated basis.

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PART I

Item 1. Business

Overview

Energy XXI Ltd, including its wholly-owned subsidiaries (“Energy XXI,” “us,” “we,” “our,” or “the Company”), is an independent oil and natural gas exploration and production company. We were originally formed and incorporated in July 2005 as an exempted company under the laws of Bermuda to serve as a vehicle for the acquisition of oil and gas reserves and related assets. In October 2005, we completed a $300 million initial public offering of our common stock and warrants on the Alternative Investment Market of the London Stock Exchange (“AIM”). On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on the Nasdaq Global Select Market (“NASDAQ”) under the symbol “EXXI.”

At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to AIM. We successfully delisted from AIM on December 15, 2014.

With our principal operating subsidiary headquartered in Houston, Texas, we are engaged in the acquisition, development, operation and exploration of oil and natural gas properties onshore in Louisiana and Texas and on the Gulf of Mexico Shelf (“GoM Shelf”). Based on production volume, we are the largest publicly traded independent operator on the GoM Shelf.

Since our inception in 2005, we have completed six major acquisitions for aggregate cash consideration of approximately $5.0 billion. In February 2006, we acquired Marlin Energy, L.L.C. (“Marlin”) for total cash consideration of approximately $448.4 million. In June 2006, we acquired Louisiana Gulf Coast producing properties from affiliates of Castex Energy, Inc. (“Castex”) for approximately $312.5 million in cash (the “Castex Acquisition”). In June 2007, we purchased certain GoM Shelf properties (the “Pogo Properties”) from Pogo Producing Company (“Pogo”) for approximately $415.1 million (the “Pogo Acquisition”). In November 2009, we acquired certain GoM Shelf oil and natural gas interests from MitEnergy Upstream LLC (“MitEnergy”), a subsidiary of Mitsui & Co., Ltd., for total cash consideration of $276.2 million (the “Mit Acquisition”). On December 17, 2010, we acquired certain shallow-water GoM Shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). On June 3, 2014, we completed the acquisition of EPL Oil & Gas, Inc. (“EPL”) for approximately $2.5 billion, including the assumption of debt (the “EPL Acquisition”). The assets acquired in the EPL Acquisition are located on the GoM Shelf. Please see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K for detailed information on the EPL Acquisition.

Our acquisitions have been primarily oil-focused at an average reserve acquisition cost of approximately $21.35 per barrel of oil equivalent (“BOE”) and have provided us access to 742,197 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,766 square miles of 3D seismic data. We own and operate 9 of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor and thus increase the total oil recovered. The techniques utilized by us include:

reviewing historical files to identify situations where partially depleted or overlooked reservoirs were determined to be uneconomic and abandoned in previous lower price environments but which now offer economic exploitation opportunities in the current price environment;
performing field studies, reservoir simulations and other analysis to identify previously overlooked, missed or under-appreciated opportunities to recover incremental oil reserves;
drilling horizontal wells that enable us to recover a higher percentage of the original oil in place per well drilled versus a vertical well by providing for a more efficient sweep mechanism that minimizes water coning;

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optimizing gas lift and other standard production techniques to optimize recovery from existing wellbores;
utilizing reprocessed 3D seismic and Wide Azimuth (“WAZ”) seismic data to better image near salt domes and improve production at existing wellbores and identify new opportunities where we can drill closer to salt domes to recover additional oil; and
injecting water through dump floods or water injection wells to increase reservoir pressure and facilitate moving additional water through the reservoir to sweep incremental oil.

The above techniques enable us to continually identify new oil weighted opportunities and maintain a large inventory of exploitation opportunities while continuing to drill in these prolific large oil reservoirs.

Our geographic concentration on the GoM Shelf enables us to realize service cost synergies. By having operations in a geographically concentrated area, we can optimize helicopter and boat charters to more efficiently service our operations. In addition, our size provides us opportunities to place service work out to bid to obtain better services and prices.

As of June 30, 2015, our estimated net proved reserves were 183.5 MMBOE, of which 75% was oil and 68% was proved developed. Natural gas liquids comprised 5% of our oil reserves. Production for the first fiscal quarter of 2016 is averaging 58,300 BOE per day, of which 71% is oil.

Business Strategy

Our goal is to strengthen our position as the largest publicly traded independent operator on the GoM Shelf, with a focus on delivering value for our shareholders. We are focused on developing high quality oil-producing assets with low production decline rates. During the second quarter of fiscal year 2015, oil prices began a substantial and rapid decline which has continued into the fiscal year 2016. In response to that decline, we initiated a series of financial and operational activities highlighted below.

Our fiscal year 2016 capital budget has been substantially reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million, and our fiscal year 2016 budget is focused on recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success, and eliminating capital commitments on exploration and other activities that do not provide incremental production.
We have reduced field level operating costs, bringing lease operating costs per barrel down by approximately 30% from fourth quarter of fiscal year 2014, and we have reduced general and administrative costs per barrel by approximately 36% from fourth quarter of fiscal year 2014 primarily through efficiencies and headcount reductions and continue to focus on operational and cost efficiencies.
We have suspended dividends on our common stock for the foreseeable future.
On March 12, 2015, we closed our private placement of $1.45 billion in aggregate principal amount of the 11.0% Senior Secured Second Lien Notes due 2020 (the “11.0% Notes”) for net proceeds of $1.35 billion, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our revolving credit facility to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016.
In connection with the issuance of the 11.0% Notes, we amended our revolving credit facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants.
On June 30, 2015, we sold the Grand Isle Gathering System (“GIGS”) for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the

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decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor, a subsidiary of CorEnergy Infrastructure Trust, Inc., pursuant to which we will continue to operate the GIGS.
In addition, on June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field.
During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices, which will provide us some price protection against further decline in oil prices. Subsequent to these transactions, we have some price protection under our hedging portfolio on approximately 27,000 barrels of crude oil per day representing approximately 70% of our estimated crude oil production volumes through December 2015 and some price protection on approximately 14,000 barrels of crude oil per day representing approximately 40% of our estimated crude oil production volumes in calendar 2016 under our hedging portfolio, which includes financially settled puts, put spreads, zero-cost collars and three-way collars. See Note 10 — “Derivative Financial Instruments” to our Consolidated Financial Statements in this Form 10-K for a detailed discussion of our hedging program.

Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and financial liquidity carefully. We expect to fund the current fiscal year 2016 capital program with cash on hand and operating cash flow. We do not expect production from our fiscal year 2016 capital program to entirely offset production declines, resulting in slight decreases to our production and related cash flows. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate, including potentially expanding our development drilling as commodity prices rebound. In addition, we expect to continue to regularly review acquisition opportunities, and we intend to evaluate and pursue potential asset sales of non-core assets to generate additional liquidity. Our acquisition strategy is to target mature, oil-producing properties on the GoM Shelf and the U.S. Gulf Coast that have not been thoroughly exploited by prior operators. We believe these activities will provide us with an inventory of low-risk recompletion and extension opportunities in our geographic area of expertise.

In addition, in light of current commodity prices and our leverage position, we continue to analyze a variety of transactions and mechanisms designed to reduce debt, including the retirement or purchase of outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

Business Strengths

To effectively execute our business strategy, we have assembled a team of engineers with an average of 19 years of industry experience and a team of geologic and geophysical experts with an average of 34 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, the members of our senior management team average 35 years of operating experience on the GoM Shelf.

Due to significant technological advancements in drilling and completion techniques, we believe our high percentage of oil reserves compared to our overall reserve base provides us with an economic advantage

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and enhances shareholder value. Additionally, the production decline curve for oil in our GoM Shelf fields is typically lower than a comparable natural gas decline curve, resulting in longer term production of current reserves.

All our assets are located on the U.S. Gulf Coast or on the GoM Shelf and we currently operate 97% 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 costs of our projects.

General Information on Properties

Below are descriptions of our significant properties at June 30, 2015. These properties represent approximately 81% of our net proved reserves and are ranked based on highest proved reserves as of June 30, 2015.

West Delta 73 Field.  We operate and have a 100% working interest in the West Delta 73 field, located 28 miles offshore of Grand Isle, Louisiana in approximately 175 feet of water on the OCS. The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline. The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 384 MMBOE. There are seven production platforms and 44 active wells located throughout the field. The field’s net production for the month of June 2015 of 6.7 MBOE/Day (“MBOED”) accounted for approximately 11% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 86% oil at June 30, 2015.

West Delta 30 Field.  We operate and have a 100% working interest in the West Delta 27, 28, 29 and 30 blocks, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on the Outer Continental Shelf (“OCS”). Blocks 27, 28 and 29 were acquired through the EPL Acquisition. The field, which was discovered in 1948 by Humble Oil and Refining, is a large salt dome. Productive sands range from 2,000 feet to 17,500 feet in depth and generally produce via strong water drive. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into compartments. The field has produced in excess of 746 MMBOE. There are 45 production structures and 98 active wells located throughout the field. The field’s net production for the month of June 2015 of 7.7 MBOED accounted for approximately 13% of our net production. Net proved reserves for the field were 84% oil at June 30, 2015. This field is the third largest oil field on the GoM Shelf, based on cumulative production to date.

South Timbalier 54 Field.  We operate and have a 100% working interest in the South Timbalier 54 field, located 36 miles offshore of Lafourche Parish, Louisiana in approximately 67 feet of water on the OCS. The field was originally discovered in 1955 by Humble Oil and Refining. The field is at the confluence of regional and counter-regional fault systems. Pleistocene through Miocene sands are trapped from 4,800 feet to 17,000 feet in shallow low relief structures over a deeper seated salt dome and in combinations of structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 149 MMBOE. There are six production platforms and 28 active wells located throughout the field. The field’s net production for the month of June 2015 of 3.2 MBOED accounted for approximately 5% of our net production. Net proved reserves for the field were 71% oil at June 30, 2015.

Main Pass 61 Field.  We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water on OCS blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 63 MMBOE since production first began in 2002, from four Upper Miocene sands. The primary producer is the J-6 Sand, which consists of a series of stratigraphic traps, located along a regional south dip. The two larger J-6 Sand stratigraphic pods are oil reservoirs that are being waterflooded to maximize recovery. There are 34 producing wells and three major production platforms located throughout the field. The field’s net production for the month of June 2015 of 7.0 MBOED accounted for approximately 12% of our net production. Net proved reserves for the field were 86% oil at June 30, 2015.

Ship Shoal 208 Field.  We operate and have a 100% working interest in the Ship Shoal 208 Field, located 110 miles southwest of New Orleans, Louisiana in approximately 100 feet of water on OCS blocks

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Ship Shoal 208, 209 and 215. The field was acquired through the EPL Acquisition. The Ship Shoal 208 Field surrounds a large salt dome and produces from over 30 Upper Pliocene through Upper Miocene reservoirs. The field was discovered by Kerr-McGee Corporation in 1961 and has produced in excess of 455 MMBbls and 1,300 BCF since production first began in 1963. We have 13 platforms and 31 active wells throughout the field. The field’s net production for the month of June 2015 of 4.8 MBOED accounted for approximately 8% of our net production. Net proved reserves for the field were 70% oil at June 30, 2015.

South Pass 49 Field.  We operate and have a 100% working interest in the South Pass 49 field, which is located near the mouth of the Mississippi River in approximately 400 feet of water. Additional interest in the field was acquired through the EPL Acquisition. The field was discovered by Gulf Oil in 1974. The field produces from Lower Pliocene sands, which consist of the Discorbis 20 thru Discorbis 70 sands, ranging in depths from 7,600 feet to 9,400 feet, on OCS blocks South Pass 33, 48, and 49. There are 14 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 121 MMBOE. The field’s net production for the month of June 2015 of 4.6 MBOED accounted for approximately 8% of our net production. Net proved reserves for the field were 62% oil at June 30, 2015.

South Pass 78.  We operate and have 100% working interest in the South Pass 78 complex. Additional interest in the field was acquired through the EPL Acquisition. The complex is located 86 miles southeast of New Orleans. It contains 31 producing wells in water depths ranging from approximately 140 to 190 feet in four lease blocks. The field was discovered in 1972 by Pennzoil Energy Co. and has produced in excess of 253 MMBOE. There are four major production platforms, three of which have producing wells, located throughout the field. The field’s net production for the month of June 2015 of 4.2 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 52% oil at June 30, 2015.

South Timbalier 21.  We operate and have a 100% working interest in the South Timbalier 21 area, located six to ten miles offshore of Lafourche Parish, Louisiana in approximately 55 feet of water on OCS blocks South Timbalier 21, 22, 23, 26, 27, 28 and 41, as well as on two state leases. Block 26 and 41 were acquired through the EPL Acquisition. The South Timbalier 21 area, discovered by Gulf Oil Company and Shell Oil Company in the late 1950s and 1960s, has produced in excess of 488 MMBOE since production began in 1957 with the exception of South Timbalier 41, discovered by EPL in 2004, which has produced in excess of 24 MMBOE. The field is bounded on the north by a major Miocene expansion fault. Miocene sands are trapped structurally and stratigraphically from 7,000 feet to 15,000 feet in depth. A large counter-regional fault, along with salt and smaller faults, creates traps and separates hydrocarbon accumulations into individual compartments. There are 22 major production platforms and 35 smaller structures located throughout the fields and 58 active wells. The area’s net production for the month of June 2015 of 2.7 MBOED accounted for approximately 5% of our net production. Net proved reserves for the field were 94% oil at June 30, 2015. This field is the tenth largest oil field on the GoM Shelf.

Ultra Deep.  With our partner Freeport McMoRan Oil & Gas, LLC, we have participated in eight projects to date, both offshore and onshore, with our participation interests ranging from approximately 9% to 23%. The operator announced on December 24, 2014, that the Highlander well completed a successful production test, which was performed in the Cretaceous/Tuscaloosa section. The operator and its partners commenced production in late February 2015. A second well location has been identified and future plans will be determined pending review of performance of the first well. The operator has identified multiple prospects in the Highlander area which provide opportunities for future development of the field and controls rights to more than 50,000 gross acres. The field’s net production for the month of June 2015 of 0.5 MBOED accounted for approximately 1% of our net production. Net proved reserves for the field were 100% gas at June 30, 2015.

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

For fiscal year 2015, proved reserves were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”), as described in further detail under “Third Party Reserves Audit” below.

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Our internal controls policies over recording of reserves estimates require reserves to be in compliance with the definitions and regulations for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance and conform to the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Our internal controls over reserves estimates include, but are not limited to the following:

NSAI is engaged by the Board of Director Audit Committee (“Audit Committee”) to perform an audit of our processes and the reasonableness of our estimates of proved reserves and has direct access to the Audit Committee;
Prior to issuance of the final reserves report, the Board of Directors meets with a representative of NSAI to review material variances, if any, between NSAI’s estimates and our estimates and to discuss any issues with the reserves evaluation process;
Lease operating statements of the previous twelve months are analyzed to determine actual historical expenses and realized prices to be used in the economic analysis. Data entered into the reserves database is checked against data determined by the lease operating statement analysis;
Updated capital costs are supplied by our Operations and Drilling Departments and entered by our reservoir engineers;
Internal reserves estimates are prepared by the area asset reservoir engineers and reviewed by asset team management;
Ownership interests, working interests and net revenue interests used in the net reserves calculation are compared against the Well Master to ensure accuracy;
Proved undeveloped property drilling (and/or development) schedules are reviewed and approved by the Audit Committee and certain members of senior management;
Senior management regularly reviews our drilling schedule and, after consultation and updates from the respective departments of the Company, approves any changes made to the existing long range plan and the related development plan. In addition, a comparison of actual proved undeveloped properties drilled (or developed) versus the associated previous fiscal year-end reserve report schedule is reviewed by the Board on a quarterly basis. This information is considered prior to approval of the current fiscal-year development schedule and associated reserves estimates.
Material reserve variances are reviewed and approved by the Director of Reserves, or his designates, to ensure compliance and accuracy;
All relevant data is compiled in a computer database application, to which only authorized personnel are given access rights consistent with their assigned job function;
All reserves estimates have appropriate back-up documentation;
Reserve estimates are finally reviewed and approved by our Director of Reserves and certain members of senior management;
The Audit Committee reviews significant changes in our reserve estimates on an annual basis.

Qualifications of Primary Internal Engineer and Third Party Engineers

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

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional

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Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Connor B. Riseden and Mr. Shane M. Howell. Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Licensed Professional Engineer in the State of Texas (No. 100566) and has over 13 years of practical experience in petroleum engineering, with over 13 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. Mr. Howell has been practicing consulting petroleum geology at NSAI since 2005. Mr. Howell is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11276) and has over 17 years of practical experience in petroleum geosciences, with over 10 years’ experience in the estimation and evaluation of reserves. 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. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The technical work was conducted by a team of nine NSAI petroleum engineers and geoscientists having an average industry experience of 17 years.

Technologies Used in Reserve Estimation

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

Third-Party Reserves Audit

The estimate of reserves disclosed in this Form 10-K for fiscal 2015 is prepared by our reservoir engineers, and we are responsible for the adequacy and accuracy of those estimates. We engaged NSAI to perform an audit of our processes and the reasonableness of our estimates of proved reserves. NSAI audited 100% of our proved reserves.

NSAI prepared its own estimates of our proved reserves by using the data and documentation with which we used to prepare our own estimates. They then compare their estimates to ours for reasonableness. NSAI also examined our reserves categorization and future producing rates, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

In conducting the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.

When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves as of June 30, 2015, based upon their evaluation concluding that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s letter is attached as Exhibit 99.1 to this Form 10-K.

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Summary of Oil and Gas Reserves at June 30, 2015

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our internal reservoir engineers and were audited by NSAI. Reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

           
  Summary of Oil and Gas Reserves as of June 30, 2015
Based on Average Fiscal-Year Prices
     Oil
MMBbls
  NGLs
MMBbls
  Natural
Gas Bcf
  MMBOE   Percent of
Total Proved
  PV-10
(in thousands)(1)
Proved
                                                     
Developed     88.6       5.4       188.0       125.3       68 %    $ 1,950,353  
Undeveloped     41.0       2.1       90.5       58.2       32 %      884,083  
Total proved     129.6       7.5       278.5       183.5             2,834,436  
Future income taxes                                                  168,655  
Less present value discount at 10%                                   91,629  
Future income taxes discounted at 10%                                   77,026  
Standardized measure of future discounted net cash flows                                 $ 2,757,410  

(1) We refer to “PV-10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and development costs. PV-10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure. Management believes that the non-U.S. GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP. Average prices (calculated using the average of the first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2015) used in determining future net revenues were $68.17 per barrel of oil for West Texas Intermediate benchmark plus $5.62 per barrel for crude quality and location differentials, for a total of $73.79 per barrel. For NGL’s, the average price used was $29.54 per barrel. For natural gas, the average price used was $3.08 per MMBtu.

Changes in Proved Reserves

Our proved developed reserve estimates decreased by 24.6 MMBOE or 16% to 125.3 MMBOE at June 30, 2015 from 149.9 MMBOE at June 30, 2014. The decrease was primarily due to:

Downward revision of 12.8 MMBOE, primarily due to the effect of reduced oil and gas prices,
Divestiture of 11.7 MMBOE, and
Production of 21.5 MMBOE.

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Offset by:

Additions of 8.5 MMBOE, primarily from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from six fields: South Pass 78, Lomond North, West Delta 73, Main Pass 61, South Timbalier 54 and South Pass 49, and
Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves.

Our proved undeveloped reserve estimates decreased by 38.1 MMBOE or 40% to 58.2 MMBOE at June 30, 2015 from 96.3 MMBOE at June 30, 2014. The decrease was primarily due to:

Downward revisions of 33.6 MMBOE comprised of (i) 7.3 MMBOE due to the effect of reduced oil and gas prices, (ii) 7.0 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 19.3 MMBOE due to new data and field studies. Of the 19.3 MMBOE of downward revisions due to new data and field studies, more than 80% occurred in the following seven fields: Grand Isle 16, Ship Shoal 208, South Timbalier 21, South Timbalier 26, Vermilion 164, West Delta 30 and West Delta 73, and
Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves.

Offset by:

Additions of 8.8 MMBOE, primarily from additional drilling locations to make up for the lower throughput per well in West Delta 73, a replacement location at Bayou Carlin, and from the identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 73.

Development of Proved Undeveloped Reserves

Our proved undeveloped (“PUD”) reserves at June 30, 2015 were 58.2 MMBOE. Future development costs associated with our PUD reserves at June 30, 2015 totaled approximately $823 million. In the fiscal year ended June 30, 2015, we developed approximately 13.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 21 gross, 21 net wells at a net cost of approximately $237 million.

We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our 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, with the exception of four locations totaling 3,560 MBOE or 6.1% of our PUD reserves. These four locations are to be sidetracked from existing wellbores which are still producing economically and thus cannot be drilled until the proved developed producing zones deplete.

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. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan. The following table presents the percentage of PUD reserves scheduled to be developed by fiscal year, in accordance with our long range plan.

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Year Ending June 30,   Percentage of PUD
Reserves Scheduled
to be Developed
2016     2.0 % 
2017     17.4 % 
2018     40.0 % 
2019     24.2 % 
2020     11.3 % 
2021 – 2029     5.1 % 
Total     100.0 % 

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

   
  Oil and
Natural Gas
  Future
Development
Costs
     (MBOE)   (in thousands)
Proved undeveloped reserves at June 30, 2014     96,256     $ 1,430,491  
Extensions and discoveries     8,798       171,060  
Revisions of previous estimates     (30,218 )      (288,697 ) 
Changes in prices and costs     (3,338 )      (240,002 ) 
Sales of reserves     (402 )      (12,400 ) 
Conversions to proved developed reserves     (12,945 )      (237,173 ) 
Total reduction in proved undeveloped reserves     (38,105 )      (607,212 ) 
Proved undeveloped reserves at June 30, 2015     58,151     $ 823,279  

Drilling Activity

The following table sets forth our drilling activity for each of the three years ended June 30, 2015, 2014 and 2013:

           
  Year Ended June 30,
     2015   2014   2013
     Gross   Net   Gross   Net   Gross   Net
Productive wells drilled
                                                     
Development     21.0       21.0       12.0       12.0       23.0       19.7  
Exploratory     3.0       1.7                   1.0       0.1  
Total     24.0       22.7       12.0       12.0       24.0       19.8  
Nonproductive wells drilled
                                                     
Development     1.0       1.0                   3.0       3.0  
Exploratory     1.0       0.6       1.0       1.0       3.0       2.2  
Total     2.0       1.6       1.0       1.0       6.0       5.2  

Present Activities

As of June 30, 2015, 1 gross well, representing approximately 1 net well, was being drilled.

Delivery Commitments

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

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Productive Wells

Our working interests in productive wells at June 30, 2015, and 2014 were as follows:

       
  June 30,
     2015   2014
     Gross   Net   Gross   Net
Natural gas     86       65       176       137  
Crude oil     481       438       808       713  
Total     567       503       984       850  

Acreage

Working interests in developed and undeveloped acreage at June 30, 2015 were as follows:

           
  June 30, 2015
     Developed Acres   Undeveloped Acres   Total Acres
     Gross   Net   Gross   Net   Gross   Net
Onshore     13,232       4,655       206,204       88,869       219,436       93,524  
Offshore     515,654       383,544       457,603       265,129       973,257       648,673  
Total     528,886       388,199       663,807       353,998       1,192,693       742,197  

The following table summarizes potential expiration of our onshore and offshore undeveloped acreage for the years ending June 30, 2016, 2017 and 2018.

           
  Year Ended June 30,
     2016   2017   2018
     Gross   Net   Gross   Net   Gross   Net
Onshore     54,852       30,878       12,264       7,517       2,092       680  
Offshore                 11,063       11,063       236,275       80,451  
Total     54,852       30,878       23,327       18,580       238,367       81,131  

Capital Expenditures, Including Acquisitions and Costs Incurred

The supplementary data presented reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows:

     
  Year Ended June 30,
     2015   2014   2013
     (in thousands)
Property acquisitions
                          
Proved   $     $ 2,046,879     $ 108,825  
Unevaluated     2,304       924,882       52,339  
Exploration costs     38,183       153,136       168,512  
Development cost     608,605       632,262       633,868  

Oil and Natural Gas Production and Prices

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

     
  Year Ended June 30,
     2015   2014   2013
Sales Volumes per Day
                          
Natural gas (MMcf)     102.7       89.7       88.6  
NGLs (MBbls)     2.7       2.4       2.3  
Crude oil (MBbls)     39.1       27.7       26.0  

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  Year Ended June 30,
     2015   2014   2013
Total (MBOE)     58.9       45.0       43.1  
Percent of BOE from crude oil and NGLs     71 %      67 %      66 % 
Average Sales Price
                          
Natural gas per Mcf   $ 3.13     $ 4.15     $ 3.48  
NGLs per Bbl   $ 28.09     $ 40.78     $ 38.38  
Crude oil per Bbl   $ 71.82     $ 105.86     $ 109.12  
Sales price per BOE   $ 54.41     $ 75.44     $ 75.14  

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

The following field contains 15% or more of our total proved reserves as of June 30, 2015. Our average daily production, average sales prices and production costs are as follows:

     
  Year Ended June 30,
     2015   2014   2013
West Delta 73
                          
Sales Volumes per Day
                          
Natural gas (MMcf)     4.3       7.5       9.0  
NGLs (MBbls)     0.1       0.1       0.1  
Crude oil (MBbls)     4.9       4.1       3.5  
Total (MBOE)     5.8       5.5       5.1  
Percent of BOE from crude oil and NGLs     86 %      75 %      71 % 
Average Sales Price
                          
Natural gas per Mcf   $ 3.46     $ 4.22     $ 3.46  
NGLs per Bbl   $ 25.18     $ 40.74     $ 33.50  
Crude oil per Bbl   $ 68.63     $ 105.06     $ 109.11  
Production cost per BOE   $ 19.91     $ 19.76     $ 18.54  

Production Unit Costs

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

     
  Year Ended June 30,
     2015   2014   2013
Average Cost per BOE
                          
Production costs
                          
Lease operating expense
                          
Insurance expense   $ 1.86     $ 1.90     $ 2.08  
Workover and maintenance     3.05       4.04       4.15  
Direct lease operating expense     16.64       16.31       15.23  
Total lease operating expense     21.55       22.25       21.46  
Production taxes     0.39       0.33       0.33  
Total production costs   $ 21.94     $ 22.58     $ 21.79  
Gathering and transportation   $ 0.98     $ 1.43     $ 1.54  
Depreciation, depletion and amortization rates   $ 32.81     $ 25.19     $ 23.16  

Derivative Activities

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

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Marketing and Customers

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

Shell Trading Company (“Shell”) accounted for approximately 29%, 45%, and 35% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014 and 2013, respectively. ExxonMobil accounted for approximately 26%, 43%, and 37% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014 and 2013, respectively. Chevron USA (“Chevron”) accounted for approximately 24% of our total oil and natural gas revenues during the year ended June 30, 2015. J.P. Morgan Ventures Energy Corporation accounted for 12% of our total oil and natural gas revenues during the year ended June 30, 2013. Beginning July 1, 2015, Trafigura Trading, LLC (“Trafigura”) replaced ExxonMobil and is expected to account for approximately 20 – 25% of our total oil and gas revenue from July 1, 2015 through December 31, 2015. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell or Chevron curtailed their purchases.

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

Government Regulation

Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

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

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

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

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

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

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

Market manipulation and market transparency regulations.  Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. Likewise, the Federal Trade Commission (“FTC”) holds authority to regulate wholesale petroleum markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, natural gas liquids, and crude oil, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC, FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation or, for the CFTC, triple the monetary gain to the violator, order disgorgement of profits, and recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

Oil Pipeline Regulations.  We own interests in oil pipelines regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and the rules and regulations promulgated under those laws and, thus, have interstate tariffs on file with FERC setting forth our interstate

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transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil, natural gas liquids and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.

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

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

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

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

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To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of ATP Oil and Gas, the BOEM indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.

We currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements. Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, the BOEM is actively seeking to adjust its financial assurance requirements for all companies operating in federal waters. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. Please read “Risk Factors — We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”

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

Gathering regulations.  Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status

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as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. The classification and regulation of our gathering lines may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.

Environmental Regulations

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

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

Clean Air Act, and its amendments, which governs air emissions;
Clean Water Act, which governs discharges of pollutants into waters of the United States;
Comprehensive Environmental Response, Compensation and Liability Act, which imposes strict liability where releases of hazardous substances have occurred or are threatened to occur (commonly known as “Superfund”);
Resource Conservation and Recovery Act, which governs the management of solid waste;
Endangered Species Act, Marine Mammal Protection Act, and Migratory Bird Treaty Act, which govern the protection of animals, flora and fauna;
Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States;
Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories; and
Safe Drinking Water Act, which governs underground injection and disposal activities; and
U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages.

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

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

Oil Pollution Act.  The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements on “responsible parties” related to the prevention of and response to oil spills into waters of the United States, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns joint and several, strict liability, without regard to fault, to each responsible party, for all containment and cleanup costs and a variety of public and private damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

Climate Change.  The U.S. Environmental Protection Agency (the “EPA”) has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore and offshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40 to 45% from 2012 emission levels by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.

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

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

Employees

We had 378 employees at June 30, 2015, none of which were represented by labor unions or covered by any collective bargaining agreement. We consider relations with our employees to be satisfactory and we have never experienced a work stoppage or strike. We regularly use independent consultants and contractors to perform various professional services in various areas, including in our exploration and development operations, production operations and certain administrative functions.

Available Information

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

Our web site address is www.energyxxi.com. We make available, free of charge on or through our web site, our Annual Report on Form 10-K, proxy statement, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or accessible through, our website is not incorporated by reference into this Form 10-K.

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Item 1A. Risk Factors

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

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

domestic and foreign supplies of oil and natural gas;
price and quantity of foreign imports of oil and natural gas;
actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;
level of consumer product demand, including as a result of competition from alternative energy sources;
level of global oil and natural gas exploration and production activity;
domestic and foreign governmental regulations;
level of global oil and natural gas inventories;
political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
weather conditions;
technological advances affecting oil and natural gas production and consumption;
overall U.S. and global economic conditions; and
price and availability of alternative fuels.

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

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

As of June 30, 2015, we had total indebtedness of $4,608 million and, as of September 22, 2015, we had total indebtedness of $4,185 million as a result of certain debt repurchases by the Company subsequent to June 30, 2015. Based on our current debt balance, we expect to have substantial interest payments due during fiscal year 2016, totaling $367.0 million. In addition, the majority of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. The maturity dates for our outstanding notes are as follows (debt amounts as of September 22, 2015, reflecting note repurchases completed by the company subsequent to June 30, 2015):

9.25% Senior Notes due December 15, 2017 ($750 million) (the “9.25% Senior Notes”)

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8.25% Senior Notes due February 15, 2018 ($510 million) (the “8.25% Senior Notes”)
3.0% Convertible Notes due December 15, 2018 ($400 million) (the “3.0% Convertible Notes”)
7.75% Senior Notes due June 15, 2019 ($126.3 million) (the “7.75% Senior Notes”)
11.0% Senior Secured Second Lien Notes due March 15, 2020 ($1.45 billion) (the “11.0% Notes”)
7.5% Senior Notes due December 15, 2021 ($246.3 million) (the “7.5% Senior Notes”)
6.875% Senior Notes due March 15, 2024 ($599.6 million) (the “6.875% Senior Notes”)

In addition, the maturity of certain of our outstanding indebtedness may be accelerated in certain situations. Pursuant to the indenture governing our 11.0% Notes, we will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes (December 15, 2017), if on such date the aggregate outstanding principal amount of all such notes exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes (February 15, 2018), if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million. In addition, our revolving credit facility is scheduled to mature on April 9, 2018; however, the maturity of our revolving credit facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017.

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

Restructure or refinance all or a portion of our debt;
obtain additional financing;
sell some of our assets or operations; or
reduce or delay capital expenditures, including development and exploration efforts and acquisitions.

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

our debt holders could declare all outstanding principal and interest to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements and the holders of our 11.0% Notes due March 15, 2020 could foreclose against the assets securing their notes;
the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and
we could be forced into bankruptcy or liquidation.

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

As of June 30, 2015, we had total indebtedness of $4,608 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:

impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes;
increase our vulnerability to general adverse economic and industry conditions;
result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest;
require us 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;
limit our flexibility in planning for, or reacting to, changes in our business and industry; and
place us at a competitive disadvantage to those who have proportionately less debt.

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

engaging in businesses other than the oil and gas business;
incurring or guaranteeing additional indebtedness or issuing disqualified capital stock;
making investments;
paying dividends, redeeming certain indebtedness or making other restricted payments;
entering into transactions with affiliates;
creating or incurring liens;
transferring or selling assets;
incurring dividend or other payment restrictions affecting certain subsidiaries;
consummating a merger, consolidation or sale of all or substantially all our assets; and
entering into sale/leaseback transactions.

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

Our ability to comply with these covenants will likely be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A prolonged period of oil and gas prices at current levels or a further decline could further increase the risk of our inability to comply with covenants to maintain

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specified financial ratios. A breach of any of these provisions could result in a default under our debt instruments, which could allow all amounts outstanding thereunder to be declared immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes in the event of acceleration of our outstanding indebtedness. In the event of such acceleration, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us. We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under these instruments.

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

Despite our current level of indebtedness, we may incur more debt in the future, which could further exacerbate the risks described above. The terms of the indentures governing our 11.0% Notes and our revolving credit facility would allow us to incur more secured and unsecured indebtedness, which in each case could intensify the related risks that we now face.

The indenture governing the 8.25% Senior Notes due 2018 includes restrictive covenants which adversely affect the business and operations of the combined company.

The covenants included in the indenture governing EPL’s 8.25% Senior Notes that EGC assumed in the EPL Acquisition include certain restrictive covenants that provide less operational flexibility than the covenants governing our other outstanding indebtedness. Specifically, the indenture governing the 8.25% Senior Notes, among other things, (i) will not allow pledging of EPL’s assets to secure the non-EPL tranche borrowings under our revolving credit facility, our second lien notes or any other secured indebtedness of EGC, (ii) will not permit EPL and its subsidiaries to be added as a guarantor of any notes issued by EGC or indebtedness of EGC under our revolving credit facility and (iii) restricts our ability to distribute cash from EPL to EGC or its other subsidiaries. Unless and until we are able to amend, replace or refinance the 8.25% Senior Notes, the restrictive covenants of such notes have made it more difficult to integrate our operations with EPL, rationalize our capital structure and operate the combined company in the most efficient manner. Our failure in this regard could adversely affect our future business and operations. In addition, certain defaults or an acceleration under the 8.25% Senior Notes could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness.

Continued Low Commodity Prices May Impact Our Ability to Comply With Debt Covenants

Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement at least through June 30, 2016; however, commodity prices have been extremely volatile in recent history and a protracted further decline in commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods. 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. Certain payment defaults or acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.

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

We expect to make substantial capital expenditures related to our oil and gas properties. Our capital requirements depend on numerous factors making it difficult to predict the timing and amount of such capital expenditures. We intend to primarily finance our near term capital expenditures with cash on hand. However,

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if our capital requirements vary materially from those provided for in our current projections, we may require additional financing. A decrease in expected revenues or an adverse change in market conditions could make obtaining this financing economically unattractive or impossible.

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

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

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

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

To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of another Gulf of Mexico operator, the BOEM indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.

We currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. However, with respect to our existing bonds and letters of credit with third parties, we can provide no assurance that the BOEM will consider them when determining

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the total value of additional financial assurances and/or bonding we must provide. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for certain other properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements.

Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, the BOEM is actively seeking to adjust its financial assurance requirements for all companies operating in federal waters. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance of a Notice to Lessees (“NTL”), effective October 2010, that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The idle iron NTL establishes new triggers for commencing decommissioning activities — any well that has

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not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time. Plugging or abandonment of wells may be delayed by two years if all of such wells’ hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. Moreover, as a result of the implementation of this NTL, there is expected to be increased demand for salvage contractors and equipment operating in the U.S. Gulf of Mexico, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.

In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Please read “We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”

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

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

The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. For the third and fourth quarters of fiscal year 2015, we recognized ceiling test write-downs of our oil and natural gas properties totaling $2,421.9 million.

Based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month for the 12 months ending September 30, 2015, we presently expect to incur a further impairment of $900 million to $1,200 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.

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

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

the volume, pricing and duration of our natural gas and oil hedging contracts;
supply of and demand for natural gas and oil;
actual prices we receive for natural gas and oil;
our actual operating costs in producing natural gas and oil;
the amount and timing of our capital expenditures and decommissioning costs;
the amount and timing of actual production; and
changes in governmental regulations or taxation.

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

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

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

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

We have included in this Form 10-K certain estimates of our proved reserves as of June 30, 2015 prepared in a manner consistent with our interpretation of the SEC rules relating to reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent

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petroleum consultant performing an audit of our reserve estimates. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, whether in response to a continued depressed commodity price environment or otherwise, we may have to write off reserves previously recognized as proved undeveloped. However, 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.

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

Approximately 32% of our proved reserves as of June 30, 2015 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserves data included in the reserves engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. In addition, there are external factors such as changes in commodity prices, the availability of capital, the availability of drilling rigs (capable of drilling in the given area), that could result in certain development plans being delayed and/or accelerated relative to the current schedule.

Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. For example, our proved reserves of 183.5 MMBOE and $2.8 billion of PV-10 as of June 30, 2015 were lower than our proved reserves of 246.2 MMBOE and $7.6 billion of PV-10 as of June 30, 2014 in part due to the rescheduling or write off of certain of our reserves as a result of lower oil and gas prices and reductions in our capital expenditure budget as compared to our June 30, 2014 reserve report. Delays in the development of these reserves could cause us to have to reclassify our proved reserves as unproved reserves. Please read “Business — Development of Proved Undeveloped Reserves.”

As of June 30, 2015, approximately 32% of our total proved reserves were undeveloped and approximately 16% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.

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

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

A large portion of our drilling activity is located in mature oil-producing areas of the GoM Shelf. Accordingly, increases in our future crude oil and natural gas production depend on our success in developing, 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 raising funds to acquire additional reserves.

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

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

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

We depend on our revolving credit facility for a portion of our future capital needs. In March 2015, we reduced the borrowing base under our revolving credit facility from $1,500 million to $500 million. As of June 30, 2015, we had borrowed $150 million and had $226 million in letters of credit issued under our revolving credit facility, with $124 million of remaining available borrowing capacity.

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our 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 our revolving credit facility will occur in the fall of 2015, although an early redetermination is possible. In addition, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. If oil and natural gas commodity prices continue to deteriorate, the revised borrowing base under our revolving credit facility may be reduced. If the borrowing base is reduced or maintained, the new borrowing base is subject to approval by banks holding not less than 67% of the lending commitments under our revolving credit facility, and the final borrowing base may be lower than the level recommended by the agent for the bank group. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial properties which could serve as additional collateral, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

As a result, we may be unable to obtain adequate funding under our revolving credit facility. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.

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

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

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subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and
result in our dependency upon a single or limited number of hydrocarbon basins.

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

severe weather, such as hurricanes and other adverse weather conditions;
delays or decreases in production, the availability of equipment, facilities or services;
delays or decreases in the availability of capacity to transport, gather or process production; and/or
changes in the regulatory environment.

For example, the oil and gas properties that we acquired in February 2006 were damaged by both Hurricanes Katrina and Rita, and again by Hurricanes Gustav and Ike and the oil and gas properties that we acquired in June 2007 were damaged by Hurricanes Katrina and Rita. This damage required us to spend time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “— Our insurance may not protect us against all of the operating risks to which our business is exposed.”

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

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

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

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

fires;
explosions;
blow-outs and surface cratering;
uncontrollable flows of gas, oil and formation water;
natural disasters, such as hurricanes and other adverse weather conditions;
pipe, cement, subsea well or pipeline failures;
casing collapses;
mechanical difficulties, such as lost or stuck oil field drilling and service tools;
abnormally pressured formations; and
environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.

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

injury or loss of life;

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severe damage to and destruction of property, natural resources and equipment;
pollution and other environmental damage;
clean-up responsibilities;
regulatory investigations and penalties;
suspension of our operations; and
repairs to resume operations.

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

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

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

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

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

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, including with respect to commodity prices such as for oil and natural gas, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events like the terrorist attacks on September 11, 2001, Hurricanes Ivan, Katrina, Rita, Gustav and Ike, and the April 20, 2010 Deepwater Horizon incident, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered damage from Hurricanes Ivan, Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is severe, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, we do not have, and it is unlikely we will obtain, 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.

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

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

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

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

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

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

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

We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We have leases on 54,852 gross acres (30,878 net) that could potentially expire during fiscal year 2016.

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

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

As we carry out our planned drilling program, we will not serve as operator of all planned wells. We operated approximately 97% of our proved reserves at June 30, 2015. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

the timing and amount of capital expenditures;
the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;
the operator’s expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of the reserves.

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

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

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

We sell the majority of our production to three customers.

Shell, ExxonMobil and Chevron each accounted for approximately 29%, 26% and 24%, respectively, of our total oil and natural gas revenues during the year ended June 30, 2015. Beginning July 1, 2015, Trafigura replaced ExxonMobil and is expected to account for approximately 20 – 25% of our total oil and gas revenue

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from July 1, 2015 through December 31, 2015. Our inability to continue to sell our production to Shell, Chevron or Trafigura, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

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

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

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

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

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

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

Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.

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

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

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

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a counterparty may not perform its obligation under the applicable derivative instrument;
production is less than expected;
there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and
the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures.

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

Ultra-deep trend wells may require equipment that may delay development and incur longer drilling times, which may increase costs.

We have participated in eight ultra-deep wells to date with our participations ranging from approximately 9% to 23%. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The ultra-deep wells are some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells.

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

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

We may be unable to successfully integrate the operations of the properties or businesses we acquire.

Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:

operating a larger organization;
coordinating geographically disparate organizations, systems and facilities;
integrating corporate, technological and administrative functions;
diverting management’s attention from other business concerns;
diverting financial resources away from existing operations;
increasing our indebtedness; and
incurring potential environmental or regulatory liabilities and title problems.

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The process of integrating our operations could cause an interruption of, or loss of momentum in, the 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 business activities are interrupted as a result of the integration process, our business could suffer.

In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.

We may not realize all of the anticipated benefits from our acquisitions.

We may not realize all of the anticipated benefits from our current and future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices, including with respect to commodity prices such as for oil and natural gas.

For example, following the EPL Acquisition, commodity prices significantly declined, and we have experienced a sustained low commodity price environment. As a result of the significant decline in commodity prices, we have not realized the revenue enhancements that we originally anticipated from the EPL Acquisition and have substantial additional debt to service that was incurred in connection with funding the EPL Acquisition.

The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.

Our business strategy includes a continuing acquisition program, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:

acceptable prices for available properties;
amounts of recoverable reserves;
estimates of future oil and natural gas prices;
estimates of future exploratory, development and operating costs;
estimates of the costs and timing of plugging and abandonment; and
estimates of potential environmental and other liabilities.

Our assessment of the acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we historically have not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. 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. If an acquired property does not perform as originally estimated, we may have an impairment, which could have a material adverse effect on our financial position and results of operations.

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

In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, BSEE and BOEM, each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting

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procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have also implemented and enforced new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added and more stringent regulatory restrictions in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill response plans could adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are developing and implementing new, more restrictive requirements such as, for example, the 2013 amendments to the federal Workplace Safety Rule regarding the utilization of a more comprehensive safety and environmental management system, (“SEMS”), which amended rule is sometimes referred to as SEMS II, and, more recently, the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster the offshore financial assurance and bonding program.

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

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

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

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

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

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

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

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

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

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

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

Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and are therefore not subject to FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, however, and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided

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services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.

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

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

require the acquisition of a permit before drilling commences;
restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
impose substantial liabilities for pollution resulting from operations.

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

the imposition of administrative, civil and/or criminal penalties;
incurring investigatory or remedial obligations; and
the imposition of injunctive relief, which could limit or restrict our operations.

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

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

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

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

We have ownership interests in oil pipelines that are subject to regulation by FERC. Rates for service on our system are set using FERC’s price indexing methodology. The indexing method currently allows a pipeline to increase its rates by a percentage factor equal to the change in the producer price index for

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finished goods plus 2.65 percent. When the index falls, we are required to reduce rates if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs.

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

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

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

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

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

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

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

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

We did not maintain properly designed controls over the contemporaneous formal documentation that we had historically prepared 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 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, 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

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with ASC Topic 815, Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Effective June 30, 2015, management discontinued the use of hedge accounting on all derivative contracts and does not expect the material weakness associated with hedge accounting to recur. If, in the future, we were to begin to designate our derivatives as hedges we would need to enhance our controls regarding consideration of all sources of ineffectiveness.

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

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

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

The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40 to 45% from 2012 emission levels by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or

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regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. As the number of emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.

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

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

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

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

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering

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and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

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

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

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

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

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;
data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
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;
a cyber-attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;
a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
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 our production, lower natural gas prices, and reduced revenues;
a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

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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
business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

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

We may be taxed as a United States corporation.

Energy XXI Ltd is incorporated under the laws of Bermuda because of our long-term desire to have business interests outside the United States. Currently, legislation in the United States that penalizes domestic corporations that reincorporate in a foreign country does not affect us, but future legislation could.

We plan to purchase any U.S. assets through our wholly owned subsidiary Energy XXI, Inc. and its subsidiaries, who will pay U.S. taxes on U.S. income. Energy XXI Ltd does not currently intend to engage in any business activity in the United States. However, there is a risk that some or all of our income could be challenged, and considered as effectively connected to a U.S. trade or business, and therefore subject to U.S. taxation. In consideration of this risk, Energy XXI Ltd and its U.S. subsidiaries have implemented certain operational steps to separate the U.S. operations from our other operations. In general, employees based in the United States will be employees of our U.S. subsidiaries, and will be paid for their services by such U.S. subsidiaries. Salaries of our employees who are U.S. residents and who render services to the U.S. business activities will be allocated as expenses of the U.S. subsidiaries.

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

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

U.S. persons who own our common shares may have more difficulty in protecting their interests than U.S. persons who are shareholders of a U.S. corporation.

The rights of shareholders under Bermuda law are not as extensive as the rights of shareholders under legislation or judicial precedent in many U.S. jurisdictions. Class actions and derivative actions are generally not available to shareholders under the laws of Bermuda. However, the Bermuda courts ordinarily would be expected to follow English case law precedent, which would permit a shareholder to commence an action in the name of a company to remedy a wrong done to a company where the act complained of is alleged to be beyond the corporate power of a company, is illegal or would result in the violation of our memorandum of association or bye-laws. Furthermore, consideration would be given by the court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of our shareholders than actually approved it. The winning party in such an action generally would be able to recover a portion of attorneys’ fees incurred in connection with such action. Our bye-laws provide that shareholders waive all claims or rights of action that they might have, individually or in the right of the Company, against any director or officer for any act or failure to act in the performance of such director’s or

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officer’s duties, except with respect to any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to stockholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.

Our bye-laws contain provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.

Our bye-laws contain provisions that could delay or prevent changes in our management or a change of control that a shareholder might consider favorable. For example, they may prevent a shareholder from receiving the benefit from any premium over the market price of our common shares offered by a bidder in a potential takeover. Even in the absence of a takeover attempt, these provisions may adversely affect the prevailing market price of our common shares if they are viewed as discouraging takeover attempts in the future. For example, provisions in our bye-laws that could delay or prevent a change in management or change in control include:

the board is permitted to issue preferred shares and to fix the price, rights, preferences, privileges and restrictions of the preferred shares without any further vote or action by our shareholders;
election of our directors is staggered, meaning that the members of only one of three classes of our directors are elected each year;
shareholders have limited ability to remove directors; and
in order to nominate directors at shareholder meetings, shareholders must provide advance notice and furnish certain information with respect to the nominee and any other information as may be reasonably required by the Company.

These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common shares.

The impact of Bermuda’s letter of commitment to the Organisation for Economic Co-operation and Development to eliminate harmful tax practices is uncertain and could affect our tax status in Bermuda.

Bermuda has implemented a legal and regulatory regime that the Organisation for Economic Co-operation and Development (“OECD”) has recognized as generally complying with internationally agreed standards for transparency and exchange of information for tax purposes. This standard has involved Bermuda entering into a number of bilateral tax information exchange agreements which provide that upon request the competent authorities of participating countries shall provide assistance through the exchange of information relevant to the administration or enforcement of domestic laws of the participating countries concerning taxes covered by the agreements without regard to any domestic tax interest requirement or bank secrecy for tax purposes. This includes information that is relevant to the determination, assessment and collection of such taxes, the recovery and enforcement of tax claims or the investigation or prosecution of tax matters. Information is to be exchanged in accordance with the agreements and shall be treated as confidential in the manner provided therein. Consequently, shareholders should be aware that in accordance with such arrangements (as extended or varied from time to time to comply with the current international standards, to the extent adopted by Bermuda or any other relevant jurisdiction), relevant information concerning it and/or its investment in the Company may be provided to the competent authority of a jurisdiction with which Bermuda has entered a tax information exchange agreement (or equivalent).

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Information regarding our properties is included in Item 1 “Business” of this Form 10-K.

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Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information for Common Stock

On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market under the symbol “EXXI.” On August 12, 2011, our common stock was admitted for trading on the Nasdaq Global Select Market (“NASDAQ”) and continues to trade under the symbol “EXXI.” The following table sets forth, for the periods indicated, the range of the high and low closing sales prices of our common stock as reported on the NASDAQ.

   
  Unrestricted
Common Stock
     High   Low
Fiscal 2014
                 
First Quarter   $ 30.02     $ 22.17  
Second Quarter     32.45       25.15  
Third Quarter     25.86       21.22  
Fourth Quarter     24.01       20.29  
Fiscal 2015
                 
First Quarter     23.55       11.35  
Second Quarter     11.13       2.45  
Third Quarter     4.83       2.33  
Fourth Quarter     4.61       2.63  

As of September 15, 2015, there were approximately 463 holders of record of our common stock.

Dividend Information

We paid cash dividends of $0.01 per share to holders of our common stock on March 13, 2015 and June 12, 2015. We paid cash dividends of $0.12 per share to holders of our common stock on September 12, 2014 and December 12, 2014. We paid quarterly cash dividends of $0.12 per share to holders of our common stock during the year ended June 30, 2014.

Cash dividends on our common stock were not approved and will not be paid for the first quarter of fiscal year 2016 and are not expected to be paid in the foreseeable future. The covenants in certain debt instruments to which we are a party 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.

Purchases of Equity Securities

Repurchases of Common Stock

In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The repurchase program will be funded with cash on hand or borrowings under our revolving credit facility. Any repurchased shares of common stock will be retained at the subsidiary level, subject to transfer to the parent company where they may be retired.

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In connection with the repurchase program, our Board of Directors also approved a Rule 10b5-1 plan that allows us to repurchase common stock at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. A broker selected by us has the authority under the pricing parameters and other terms and limitations specified in the 10b5-1 plan to repurchase shares on our behalf.

In November 2013, concurrently with the offering of our 3.0% Senior Convertible Notes due 2018, our Board of Directors approved an additional one time repurchase of our common stock of approximately $76 million, pursuant to which one of the Company’s wholly-owned subsidiaries repurchased 2,776,200 shares of the Company’s common stock for approximately $76 million, at a weighted average price per share, excluding fees, of $27.39.

We have not made any repurchases under our repurchase program during the fiscal year ended June 30, 2015, and we have suspended the repurchase program indefinitely to reduce our capital needs.

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Item 6. Selected Financial Data

The following information as of and for the years ended June 30, 2014, 2013, 2012, and 2011 has been updated to reflect the restatement to our financial statements as discussed in Note 22– Restatement of Previously Issued Consolidated Financial Statements of Notes to Consolidated Financial Statements in this Form 10-K. The amounts 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) to 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 test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. The following table sets forth a reconciliation of previously reported and restated net income (loss) and accumulated deficit as of the dates and for the periods shown (in thousands):

         
  Net Income (Loss)   Accumulated Deficit
     Year Ended June 30,   At June 30, 2010
     2014   2013   2012   2011
     (In thousands)
Previously reported   $ 59,111     $ 162,081     $ 335,827     $ 64,655     $ (492,867 ) 
Pre-tax adjustments:
                                            
Change in accounting for derivative financial instruments     (72,348 )      (47,770 )      193,980       (147,984 )      42,660  
Related impact on ceiling test impairment                             (187,800 ) 
Related impact on depreciation, depletion and amortization     9,293       12,433       16,894       18,926       32,916  
Total pre-tax adjustments     (63,055 )      (35,337 )      210,874       (129,058 )      (112,224 ) 
Related income tax provision (benefit)     (22,069 )      (54,039 )      67,893       (51,794 )      14,954  
Net after-tax adjustments     (40,986 )      18,702       142,981       (77,264 )      (127,178 ) 
Restated   $ 18,125     $ 180,783     $ 478,808     $ (12,609 )    $ (620,045 ) 

You should read the selected consolidated historical financial information set forth below in conjunction with our restated Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our restated audited consolidated financial statements and the notes thereto included in Part II, Item 8, “Financial Statements and Supplementary Data,” of this Form 10-K.

We have derived the following selected consolidated financial information as of June 30, 2015 and 2014 and for the years ended June 30, 2015, 2014 and 2013 from the audited consolidated financial statements included in Part II, Item 8, “Financial Statements and Supplementary Data.” We have derived the selected consolidated financial information as of June 30, 2013, 2012 and 2011 and for the years ended June 30, 2012 and 2011 from our restated consolidated financial information.

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We have not amended our previously filed Annual Reports on Form 10-K or Quarterly Reports on Form 10-Q for the periods affected by the restatement. We have included in Part II, Item 8, “Financial Statements and Supplementary Data,” restated quarterly financial statements for the three months ended September 30, 2014 and 2013 the three and six months ended December 31, 2014 and 2013, and the three and nine months ended March 31, 2015 and 2014. The financial information that has been previously filed or otherwise reported for these periods is superseded by the information in this Form 10-K, and the financial statements and related financial information contained in such previously filed reports should no longer be relied upon. These historical results are not necessarily indicative of results to be expected for any future periods.

         
  Year Ended June 30,
     2015   2014(1)
(Restated)
  2013
(Restated)
  2012
(Restated)
  2011
(Restated)
     (In thousands, except per share amounts)
Income Statement Data
                                            
Revenues   $ 1,405,452     $ 1,153,123     $ 1,158,932     $ 1,504,611     $ 716,950  
Depreciation, depletion and amortization (“DD&A”)     705,521       414,026       363,791       350,569       274,553  
Impairment of oil and natural gas properties     2,421,884                          
Goodwill impairment     329,293                          
Operating income (loss)     (2,710,891 )      217,806       326,081       694,158       79,865  
Other (expense) – net     (336,297 )      (164,661 )      (112,704 )      (108,811 )      (132,006 ) 
Net income (loss)     (2,433,838 )      18,125       180,783       478,808       (12,609 ) 
Basic earnings (loss) per common share   $ (25.97 )    $ 0.09     $ 2.14     $ 5.95     $ (0.75 ) 
Diluted earnings (loss) per common share   $ (25.97 )    $ 0.09     $ 1.94     $ 5.27     $ (0.75 ) 
Cash Flow Data
                                            
Provided by (used in)
                                            
Operating activities   $ 330,753     $ 545,460     $ 638,148     $ 785,514     $ 387,725  
Investing activities
                                            
Acquisitions     (301 )      (849,641 )      (161,164 )      (6,401 )      (1,012,262 ) 
Investment in properties     (723,829 )      (788,676 )      (816,105 )      (570,670 )      (281,233 ) 
Proceeds from the sale of properties     261,931       126,265             2,750       38,431  
Other     1,751       (32,523 )      (16,734 )      4,728       (8 ) 
Total investing activities     (460,448 )      (1,544,575 )      (994,003 )      (569,593 )      (1,255,072 ) 
Financing activities     740,737       1,144,921       238,768       (127,241 )      881,530  
Increase (decrease) in cash     611,042       145,806       (117,087 )      88,680       14,183  
Dividends Paid per Common Share   $ 0.26     $ 0.48     $ 0.33     $ 0.07     $  

         
  June 30,
     2015   2014
(Restated)
  2013
(Restated)
  2012
(Restated)
  2011
(Restated)
     (In thousands)
Balance Sheet Data
                                            
Total assets   $ 4,690,829     $ 7,341,497     $ 3,505,080     $ 3,011,882     $ 2,662,901  
Long-term debt including current maturities     4,608,432       3,759,644       1,370,045       1,018,344       1,113,387  
Stockholders’ equity (deficit)     (728,722 )      1,734,560       1,367,935       1,286,776       810,738  
Common shares outstanding     94,643       93,720       76,486       78,838       76,203  

(1) On June 3, 2014, we completed the EPL Acquisition which significantly increased our scope of operation. See Note 3 — “Acquisitions and Dispositions” to our Consolidated Financial Statements in this Form 10-K.

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  Year Ended June 30,
Operating Highlights   2015   2014
(Restated)
  2013
(Restated)
  2012
(Restated)
  2011
(Restated)
     (In thousands, except per unit amounts)
Operating revenues
                                            
Oil sales   $ 1,052,731     $ 1,104,208     $ 1,067,687     $ 1,186,193     $ 777,869  
Natural gas sales     117,282       135,883       112,753       88,608       101,813  
Gain (loss) on derivative financial instruments     235,439       (86,968 )      (21,508 )      229,809       (162,732 ) 
Total revenues     1,405,452       1,153,123       1,158,932       1,504,610       716,950  
Percentage of operating revenues from
crude oil
                                            
Prior to gain (loss) on derivative financial instruments     90 %      89 %      90 %      93 %      88 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     40,046       31,183       32,737       28,521       27,876  
Workover and maintenance     65,562       66,481       65,118       56,413       33,095  
Direct lease operating expense     357,927       268,083       239,308       225,881       178,507  
Total lease operating expense     463,535       365,747       337,163       310,815       239,478  
Production taxes     8,385       5,427       5,246       7,261       3,336  
Gathering and transportation     21,144       23,532       24,168       16,371       12,499  
DD&A     705,521       414,026       363,791       350,569       274,553  
Accretion of asset retirement obligations     50,081       30,183       30,885       39,161       32,127  
Impairment of oil and natural gas properties     2,421,884                          
Goodwill impairment     329,293                          
General and administrative     116,500       96,402       71,598       86,276       75,091  
Total operating expenses     4,116,343       935,317       832,851       810,453       637,084  
Operating income (loss)   $ (2,710,891 )    $ 217,806     $ 326,081       694,157       79,866  
Sales volumes per day
                                            
Natural gas (MMcf)     102.7       89.7       88.6       81.5       67.2  
Crude oil (MBbls)     41.8       30.1       28.3       30.5       23.4  
Total (MBOE)     58.9       45       43.1       44.1       34.6  
Percent of sales volumes from crude oil     71 %      67 %      66 %      69 %      68 % 
Average sales price
                                            
Oil per Bbl   $ 68.99     $ 100.59     $ 103.48     $ 106.17     $ 90.95  
Natural gas per Mcf     3.13       4.15       3.48       2.97       4.15  
Gain (loss) on derivative financial instruments per BOE     10.95       (5.29 )      (1.37 )      14.24       (12.87 ) 
Total revenues per BOE     65.36       70.16       73.77       93.21       56.71  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     1.86       1.90       2.08       1.77       2.21  
Workover and maintenance     3.05       4.04       4.15       3.49       2.62  
Direct lease operating expense     16.64       16.31       15.23       13.99       14.12  
Total lease operating expense per BOE     21.55       22.25       21.46       19.25       18.95  
Production taxes     0.39       0.33       0.33       0.45       0.26  
Gathering and transportation     0.98       1.43       1.54       1.01       0.99  
DD&A     32.81       25.19       23.16       21.72       21.72  
Accretion of asset retirement obligations     2.33       1.84       1.97       2.43       2.54  
Impairment of oil and natural gas properties     112.63                          
Goodwill impairment     15.31                          
General and administrative     5.42       5.87       4.56       5.34       5.94  
Total operating expenses per BOE     191.42       56.91       53.02       50.20       50.40  
Operating income (loss) per BOE   $ (126.06 )    $ 13.25     $ 20.75     $ 43.01     $ 6.31  

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TABLE OF CONTENTS

         
  Quarter Ended
Operating Highlights   June 30,
2015
  March 31,
2015
(Restated)
  December 31,
2014
(Restated)
  September 30,
2014
(Restated)
  June 30,
2014
(Restated)
     (In thousands, except per unit amounts)
Operating revenues
                                            
Oil sales   $ 225,263     $ 177,605     $ 279,708     $ 370,155     $ 294,975