10-K 1 v385304_10k.htm FORM 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, 2014

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 (Bermuda) Limited

(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 x No o

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 x   Accelerated filer o
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 $925,761,391 based on the closing sale price of $27.06 per share as reported on The NASDAQ Global Select Market on December 31, 2013, 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 July 31, 2014 was 93,865,377.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2014 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2014, 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     1  
PART I
 

Item 1

Business

    2  

Item 1A

Risk Factors

    19  

Item 1B

Unresolved Staff Comments

    44  

Item 2

Properties

    44  

Item 3

Legal Proceedings

    44  

Item 4

Mine Safety Disclosures

    44  
           
PART II
 

Item 5

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

    45  

Item 6

Selected Financial Data

    47  

Item 7

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

    50  

Item 7A

Quantitative and Qualitative Disclosures About Market Risk

    70  

Item 8

Financial Statements and Supplementary Data

    73  

Item 9

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

    128  

Item 9A

Controls and Procedures

    128  

Item 9B

Other Information

    128  
PART III
 

Item 10

Directors, Executive Officers and Corporate Governance

    129  

Item 11

Executive Compensation

    129  

Item 12

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

    129  

Item 13

Certain Relationships and Related Transactions, and Director Independence

    129  

Item 14

Principal Accounting Fees and Services

    129  
           
PART IV
 

Item 15

Exhibits, Financial Statement Schedules

    130  
Signatures     137  

i


 
 

TABLE OF CONTENTS

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).

Cash-flow hedges are derivative instruments used to mitigate the risk of variability in cash flows from crude oil and natural gas sales due to changes in market prices. Examples of such derivative instruments include fixed-price swaps, fixed-price swaps combined with basis swaps, purchased put options, costless collars (purchased put options and written call options) and producer three-ways (purchased put spreads and written call options). These derivative instruments either fix the price a party receives for its production or, in the case of option contracts, set a minimum price or a price within a fixed range.

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, a service well or a stratigraphic test well.

Fair-value hedges are derivative instruments used to hedge or offset the exposure to changes in the fair value of a recognized asset or liability or an unrecognized firm commitment. For example, a contract is entered into whereby a commitment is made to deliver to a customer a specified quantity of crude oil or natural gas at a fixed price over a specified period of time. In order to hedge against changes in the fair value of these commitments, a party enters into swap agreements with financial counterparties that allow the party to receive market prices for the committed specified quantities included in the physical contract.

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.

ii


 
 

TABLE OF CONTENTS

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 Company’s working interest percentage 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 our wells and related equipment and facilities.

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 formation. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.

iii


 
 

TABLE OF CONTENTS

Stratigraphic test well refers to a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.

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.

iv


 
 

TABLE OF CONTENTS

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. Known material factors that could cause actual results to differ materially from those in the forward-looking statements include those described in (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.

1


 
 

TABLE OF CONTENTS

PART I

Item 1. Business

Overview

Energy XXI (Bermuda) Limited and 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”).

Headquartered in Houston, Texas, we are engaged in the acquisition, exploration, development and operation of oil and natural gas properties onshore in Louisiana and Texas and on the Gulf of Mexico Shelf (“GoM Shelf”). Energy XXI is the largest publicly traded independent operator on the GoM Shelf, operating seven of the largest GoM Shelf fields.

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 Gulf of Mexico 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, which we expect to integrate with our existing portfolio on the GoM Shelf and provide significant near term cost savings. 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 767,445 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,036 square miles of 3D seismic data. We own and operate seven of the 15 largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor to 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 lower price environments but which now offer economic exploitation opportunities in a $100 per barrel oil price environment;
performing field studies, reservoir simulations and other analysis to identify previously overlooked, missed or under-appreciated opportunities to recover incremental oil reserves;
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;
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;

2


 
 

TABLE OF CONTENTS

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; and
optimizing gas lift and other standard production techniques to optimize recovery from existing wellbores.

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, 2014, our estimated net proved reserves were 246.2 MMBOE, of which 75% was oil and 61% was proved developed. Natural gas liquids comprised 5% of our oil reserves. Our current production is approximately 60,000 BOE per day, of which 69% is oil.

Business Strategy

Energy XXI’s goal is to grow and strengthen its 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 and exploring high quality oil-producing assets with low production decline rates.

We pursue growth opportunities through exploration and development drilling on our existing core properties to enhance production and ultimate recovery of reserves, supplemented by strategic acquisitions from time to time. 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 areas will provide us with an inventory of low-risk recompletion and drilling opportunities in our geographic area of expertise. We finance acquisitions with a combination of funds from our equity offerings, debt offerings, bank borrowings and cash generated from operations.

We plan to deploy a portion of our exploration budget to explore two play concepts on the GoM Shelf; namely the counter regional salt play and the ultra-deep play. We have acreage on 14 salt domes and are currently acquiring Full Azimuth Nodal (“FAN”) seismic data to identify potentially liquid-rich deep reservoirs around these salt domes. Existing facilities surrounding the properties may shorten cycle time from discovery to production as we believe we may be able to tie in new discoveries to existing infrastructure. Drilling around salt domes may commence as early as the first part of calendar year 2015. In the ultra-deep play, we are currently participating in eight projects. Certain of these projects are in various stages of activity as described below under “Ultra-Deep and Salt Play Activity.”

The EPL Acquisition significantly increased our enterprise value not only through the issuance of new common stock, but also significantly increased our indebtedness and debt to total capitalization percentage. Accordingly, our focus in the near term will be:

merging the two asset portfolios and high-grading our drilling inventory;
deploying capital resources on low-risk development drilling in the fields where we have previously enjoyed success;
reducing capital spending on exploration drilling and pursuing opportunities with third parties to have them participate in certain exploration projects with us;
continuing to de-risk our drilling program by focusing on execution through repeatable and predictable programs that will allow oil growth in core properties; and
maximizing cash flow to reduce leverage and pay down debt.

3


 
 

TABLE OF CONTENTS

Business Strengths

To effectively execute our business strategy, we have assembled a team of engineers with an average of 18 years of industry experience and a team of geologic and geophysical experts with an average of 33 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, the members of our senior management team average 31 years of operating experience on the GoM Shelf.

With the current prices of crude oil and 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 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 96% 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, 2014, which represent approximately 81% of our net proved reserves, and are ranked based on highest proved reserves as of June 30, 2014.

West Delta 73.  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 381 MMBOE. There are seven production platforms and 46 active wells located throughout the field. The field’s net production for the month of June 2014 of 4.6 MBOE/Day (“MBOED”) accounted for approximately 8% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 83% oil at June 30, 2014.

West Delta 27, 28, 29 and 30 blocks.  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 740 MMBOE. There are 39 production structures and 90 active wells located throughout the field. The field’s net production for the month of June 2014 of 9.0 MBOED accounted for approximately 15% of our net production. Net proved reserves for the field were 88% oil at June 30, 2014. This field is the largest oil field on the GoM Shelf, based on cumulative production to date.

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 57 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 26 producing wells and three major production platforms located throughout the field. The field’s net production for the month of June 2014 of 7.6 MBOED accounted for approximately 13% of our net production. Net proved reserves for the field were 84% oil at June 30, 2014.

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

4


 
 

TABLE OF CONTENTS

structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 146 MMBOE. There are six production platforms and 25 active wells located throughout the field. The field’s net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 73% oil at June 30, 2014.

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 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 221 MMBbls and 1,300 BCF since production first began in 1963. We have 11 platforms and 27 active wells throughout the field. The field’s net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 67% oil at June 30, 2014.

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 which have 15 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 118 MMBOE. The field’s net production for the month of June 2014 of 4.0 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 59% oil at June 30, 2014.

South Pass 78.  We operate the South Pass 78 complex and own a working interest of 100% of the acreage position in this area. Additional interest in the field was acquired through the EPL Acquisition. The complex is located 86 miles southeast of New Orleans. It contains 23 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 237 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 2014 of 1.9 MBOED accounted for approximately 3% of our net production. Net proved reserves for the field were 60% oil at June 30, 2014.

Grand Isle 16/18.  We operate and have a 100% working interest in the Grand Isle 16/18 field, located seven miles offshore of Lafourche Parish, Louisiana in approximately 50 feet of water on the OCS. The field was originally discovered in 1948 by Humble Oil and Refinery and production began in 1948. The field consists of two separate shallow piercement salt domes. Pleistocene through Miocene Sands are trapped structurally and stratigraphically from 6,000 feet to 13,000 feet in depth against the salt piercements. Radial faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 523 MMBOE. There are 13 production platforms and 57 active wells located throughout the field. The field’s average net production for the month of June 2014 of 4.4 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 78% oil at June 30, 2014. This field is the fifth largest oil field on the GoM Shelf.

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 41 was 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 512 MMBOE since production began in 1957 with the exception of South Timbalier 41, discovered by Energy Partners 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 20 major production platforms and 56 smaller structures located throughout the fields and 66 active wells. The area’s net production for the month of June 2014 of 3.3 MBOED accounted for approximately 6% of our net production. Net proved reserves for the field were 88% oil at June 30, 2014. This field is the fourth largest oil field on the GoM Shelf.

5


 
 

TABLE OF CONTENTS

East Bay.  We operate this field and own an average 96% working interest in our acreage position in this area. The field includes the South Pass 24 and 27 fields and is located 89 miles southeast of New Orleans, near the mouth of the Mississippi River. The field was acquired through the EPL Acquisition. It contains 197 producing wells located along the coastline and in water depths up to approximately 70 feet. The field was discovered by Shell in the early 1950s and has produced over 900 MMBOE to date. Over 1,400 wells have been drilled to develop approximately 70 hydrocarbon bearing sands. The field is divided by a major east-west fault with South Pass 24 field being on the north or up thrown side of the fault and South Pass 27 field being on the south or down thrown side of the fault. Producing depths vary from a few thousand feet to over 13,000 feet true vertical depth (“TVD”). The field’s net production for the month of June 2014 of 2.2 MBOED accounted for approximately 4% of our net production. Net proved reserves for the field were 95% oil at June 30, 2014.

Ultra-Deep and Salt Play Activity

Our partnership with the operator Freeport McMoRan Oil and Gas, LLC (formerly McMoRan Exploration Company and now acquired by Freeport-McMoRan, Inc.) retains a leading acreage position in the emerging Inboard Lower Tertiary and Cretaceous gas trend, located in the GoM Shelf and onshore South Louisiana. We have participated in eight projects to date, both offshore and onshore, with our participations ranging from approximately 9% to 20%. This emerging exploration trend focuses on the subsalt Lower Wilcox and Cretaceous sections. The Lomond North well is in the process of being completed and the Davy Jones No. 2 well was determined to be non-commercial in the Tuscaloosa sand and awaiting test of Wilcox sands.

In our joint venture with Fieldwood Energy, LLC (“Fieldwood”) and Apache Corporation (“Apache”) in the Main Pass area, we have drilled two wells on the Main Pass 295 structure. The #1 BP1 well was drilled to a depth of 19,555 feet MD/19,510 feet TVD on the southern flank of the salt dome, penetrating eight oil sands and one gas-bearing sand. An offset well, the MP 295 #3, was drilled to a depth of 10,561 feet MD/10,332 feet TVD and also has encountered multiple hydrocarbon-bearing sands. Both wellbores have been suspended for future use. This joint venture is expecting 3D-WAZ seismic data analysis to be completed in January 2015.

We are currently negotiating an extension of our joint venture with ExxonMobil in the Vermilion area with a plan to reprocess 3D seismic data during 2014 to help determine future drilling activity.

Reserve Estimation Procedures and Internal Controls over Reserve Estimates

For fiscal year 2014, 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.

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 Directors 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 final reserves report issuance, the Board of Directors meets with a NSAI representative to review material variances, if any, between NSAI’s estimates and the Company’s 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;

6


 
 

TABLE OF CONTENTS

Internal reserves estimates are prepared by the area asset reservoir engineers and reviewed by the asset team management;
Ownership, working interest and net revenue interest, used in the net reserves calculation are compared against the Well Master to ensure accuracy;
Proved undeveloped properties scheduling is checked for consistency with the Company’s budget and long range plan which demonstrate the Company’s commitment to develop those locations;
Material reserve variances are reviewed and approved by the Director of Reserves and Business Planning, 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 Business Planning and certain members of senior management;
The Audit Committee reviews significant reserve changes on an annual basis.

Qualifications of Primary Internal Engineer and Third Party Engineers

Our Director of Reserves and Business Planning is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has 29 years of industry experience with positions of increasing responsibility. The Director of Reserves and Business Planning directly reports to our Chief Financial Officer.

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 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 12 years of practical experience in petroleum engineering, with over 12 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 15 years of practical experience in petroleum geosciences, with over 9 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 11 NSAI petroleum engineers and geoscientists having an average industry experience of 22 years.

Technologies Used in Reserve Estimation

The SEC’s reserves rules expanded the technologies that a company can use to establish reserves. The SEC now 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.

7


 
 

TABLE OF CONTENTS

Third-Party Reserves Audit

The estimate of reserves disclosed in this Form 10-K for fiscal 2014 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, 2014, 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.

Summary of Oil and Gas Reserves at June 30, 2014

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, 2014
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     106.9       5.9       222.9       149.9       61 %    $ 4,267,430  
Undeveloped     68.9       3.7       142.0       96.3       39 %      3,334,074  
Total Proved     175.8       9.6       364.9       246.2                 7,601,504  
Future Income taxes                                                  2,546,155  
Less 10% discount                                   892,176  
Future income taxes discounted at 10%                                   1,653,979  
Standardized measure of future discounted net cash flows                                 $ 5,947,525  

(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

8


 
 

TABLE OF CONTENTS

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, 2014) used in determining future net revenues were $96.75 per barrel of oil for West Texas Intermediate benchmark plus $7.05 per barrel for crude quality and location differentials, for a total of $103.80 per barrel. For NGL’s, the average price used was $42.10 per barrel. For natural gas, the average price used was $4.10 per MMBtu.

Changes in Proved Reserves

Our proved developed reserve estimates increased by 40.4 MMBOE or 37% to 149.9 MMBOE at June 30, 2014 from 109.5 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 52.3 MMBOE, primarily in the EPL Acquisition.
Additions of 5.4 MMBOE from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from the 4 fields: West Delta 30, Main Pass 61, Main Pass 73 and Grand Isle 16.

Offset by:

Downward revision of 2.7 MMBOE, mainly due to lower than forecasted per well throughput at West Delta 73 and sanding issues at South Timbalier 54, offset by positive performance revision at West Delta 30 and South Pass 49
Divestiture of 4.7 MMBOE, and
Production of 16.4 MMBOE.

Our proved undeveloped reserve estimates increased by 27.3 MMBOE or 40% to 96.3 MMBOE at June 30, 2014 from 69.0 MMBOE at June 30, 2013. The increase was primarily due to:

Acquisitions of 24.6 MMBOE, primarily in the EPL Acquisition.
Additions of 15.1 MMBOE, primarily additional drilling locations to make up for the lower throughput per well in West Delta 73, replacement locations for South Timbalier 54 and from identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 61.

Offset by:

Downward revision of 5.9 MMBOE, primarily due to lease expiration in South Fresh Water Bayou, reallocation of reserves due to new information from the drilling program in Main Pass 61, and change of fluid type due to new information from the drilling program in West Delta 30.
Conversion of 6.6 MMBOE from proved undeveloped to proved developed reserves.

Development of Proved Undeveloped Reserves

Our proved undeveloped (“PUD”) reserves at June 30, 2014 were 96.3 MMBOE. Future development costs associated with our PUD reserves at June 30, 2014 totaled approximately $1,430 million. In the fiscal year ended June 30, 2014, we developed approximately 9.5% of our PUD reserves included in our June 30,

9


 
 

TABLE OF CONTENTS

2013 reserve report, consisting of 18 gross, 18 net wells at a net cost of approximately $160.9 million. In addition, we also spent $101.7 million in developing PUD reserves that were still in progress at the end of the fiscal year ended June 30, 2014.

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 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 report, with the exception of two. These two locations are to be sidetracked from existing wellbores which are still producing economically, thus cannot be drilled until the proved developed producing zones deplete.

The following table discloses our progress toward the development of PUD reserves during the fiscal year ended June 30, 2014.

   
  Oil and
Natural Gas
  Future Development Costs
     (MBOE)   (In thousands)
Proved undeveloped reserves at June 30, 2013     69,007     $ 1,039,918  
Extensions and discoveries     15,072       315,375  
Revisions of previous estimates     (6,183 )      4,966  
Changes in prices and costs     314       10,465  
Purchases of reserves in place     24,627       307,632  
Conversions to proved developed reserves     (6,581 )      (247,865 ) 
Total proved undeveloped reserves added     27,249       390,573  
Proved undeveloped reserves at June 30, 2014     96,256     $ 1,430,491  

Drilling Activity

The following table sets forth our drilling activity for the three years ended June 30, 2014, 2013 and 2012:

           
  Year Ended June 30,
     2014   2013   2012
     Gross   Net   Gross   Net   Gross   Net
Productive wells drilled
                                                     
Development     12       12       23.0       19.7       13.0       10.4  
Exploratory                 1.0       0.1              
Total     12       12       24.0       19.8       13.0       10.4  
Nonproductive wells drilled
                                                     
Development                 3.0       3.0       1.0       0.1  
Exploratory     1       1       3.0       2.2       2.0       1.3  
Total     1       1       6.0       5.2       3.0       1.4  

Present Activities

As of June 30, 2014, 11 gross wells, representing approximately 8.5 net wells, were being drilled.

Delivery Commitments

We had no delivery commitments in the three years ended June 30, 2014.

10


 
 

TABLE OF CONTENTS

Productive Wells

Our working interests in productive wells at June 30, 2014, and 2013 were as follows:

       
  June 30,
     2014   2013
     Gross   Net   Gross   Net
Natural Gas     176       137       91       51  
Crude Oil     808       713       372       284  
Total     984       850       463       335  

Acreage

Working interests in developed and undeveloped acreage at June 30, 2014 were as follows:

           
  June 30, 2014
     Developed Acres   Undeveloped Acres   Total Acres
     Gross   Net   Gross   Net   Gross   Net
Onshore     37,279       36,206       131,652       46,012       168,931       82,218  
Offshore     555,084       396,748       590,241       288,479       1,145,325       685,227  
Total     592,363       432,954       721,893       334,491       1,314,256       767,445  

The following table summarizes potential expiration of our onshore and offshore undeveloped acreage for the years ending June 30, 2015, 2016 and 2017.

           
  Year Ending June 30,
     2015   2016   2017
     Gross   Net   Gross   Net   Gross   Net
Onshore     17,150       12,334       55,845       22,758       30,676       5,405  
Offshore     87,651       25,465       23,040       7,200       20,603       20,603  
Total     104,801       37,799       78,885       29,958       51,279       26,008  

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,
     2014   2013   2012
     (In Thousands)
Property acquisitions
                          
Proved   $ 2,046,879     $ 108,825     $ 6,401  
Unevaluated     924,882       52,339        
Exploration costs     153,136       168,512       183,397  
Development costs     632,262       633,868       327,360  

11


 
 

TABLE OF CONTENTS

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,
     2014   2013   2012
Sales Volumes per Day
                          
Natural gas (MMcf)     89.7       88.6       81.5  
NGLs (MBbls)     2.4       2.3       2.8  
Crude oil (MBbls)     27.7       26.0       27.7  
Total (MBOE)     45.0       43.1       44.1  
Percent of BOE from crude oil and NGLs     67 %      66 %      69 % 
Average Sales Price
                          
Natural gas per Mcf   $ 4.15     $ 3.48     $ 2.97  
Hedge gain per Mcf     0.11       0.47       0.94  
Total natural gas per Mcf   $ 4.26     $ 3.95     $ 3.91  
NGLs per Bbl   $ 40.78     $ 38.38     $ 53.73  
Crude oil per Bbl   $ 105.86     $ 109.12     $ 111.41  
Hedge gain (loss) per Bbl     (1.28 )      1.40       0.04  
Total crude oil per Bbl   $ 104.58     $ 110.52     $ 111.45  
Sales price per BOE   $ 75.44     $ 75.14     $ 78.97  
Hedge gain (loss) per BOE     (0.56 )      1.81       1.77  
Total sales price per BOE   $ 74.88     $ 76.95     $ 80.74  

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, 2014. Our average daily production, average sales prices and production costs follow:

     
  Year Ended June 30,
     2014   2013   2012
West Delta 73
                          
Sales Volumes per Day
                          
Natural gas (MMcf)     7.5       9.0       6.0  
NGLs (MBbls)     0.1       0.1       0.1  
Crude oil (MBbls)     4.1       3.5       2.3  
Total (MBOE)     5.5       5.1       3.4  
Percent of BOE from crude oil and NGLs     75 %      71 %      71 % 
Average Sales Price
                          
Natural gas per Mcf   $ 4.22     $ 3.46     $ 1.67  
NGLs per Bbl   $ 40.74     $ 33.50     $ 61.18  
Crude oil per Bbl   $ 105.06     $ 109.11     $ 111.33  
Production Costs per BOE   $ 19.76     $ 18.54     $ 21.30  

12


 
 

TABLE OF CONTENTS

Production Unit Costs

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

     
  Year Ended June 30,
     2014   2013   2012
Average Costs per BOE
                          
Production costs
                          
Lease operating expense
                          
Insurance expense   $ 1.90     $ 2.08     $ 1.77  
Workover and maintenance     4.04       4.15       3.49  
Direct lease operating expense     16.31       15.23       13.99  
Total lease operating expense     22.25       21.46       19.25  
Production taxes     0.33       0.33       0.45  
Total production costs   $ 22.58     $ 21.79     $ 19.70  
Gathering and transportation   $ 1.43     $ 1.54     $ 1.01  
Depreciation, depletion and amortization rates   $ 25.75     $ 23.95     $ 22.76  

Derivative Activities

We actively manage price risk and hedge a high percentage of our proved developed producing reserves to enhance revenue certainty and predictability. In connection with our acquisitions, we may enter into hedging arrangements to minimize commodity downside exposure. Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges and expect to carry those hedges through the end of contract term beginning from June 2014 through December 2015. We believe that our disciplined risk management strategy provides substantial price protection so that our cash flow is largely driven by production results rather than commodity prices. This greater price certainty allows us to efficiently allocate our capital resources and minimize our operating costs. For further information regarding our risk management activities, please read Item 7A “Quantitative and Qualitative Disclosures About Market Risk” in this Form 10-K.

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 45%, 35% and 32% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. ExxonMobil accounted for approximately 43%, 37% and 37% of our total oil and natural gas revenues during the years ended June 30, 2014, 2013 and 2012, respectively. J.P. Morgan Ventures Energy Corporation accounted for 12% and 18% of our total oil and natural gas revenues during the years ended June 30, 2013 and 2012, respectively. 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 ExxonMobil 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

13


 
 

TABLE OF CONTENTS

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

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

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

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

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

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

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

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

14


 
 

TABLE OF CONTENTS

we are required to observe these anti-market manipulation laws and related regulations enforced by FERC, FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation or, for the CFTC, triple the monetary gain to the violator, order disgorgement of profits, and recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.

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

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

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

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

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

15


 
 

TABLE OF CONTENTS

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”), successor agencies to the Minerals Management Service. These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency, (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such obligations. The cost of such bonds or other surety can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. Under certain circumstances, the BSEE, a new federal agency created to enforce compliance with safety and environmental rules applicable to OCS activities, may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. We own certain crude oil pipelines located on the OCS. BSEE regulates terms of service on OCS pipelines to provide open and nondiscriminatory access.

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

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

16


 
 

TABLE OF CONTENTS

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 Protected Areas, Marine Mammal Protection Act, Migratory Bird Treaty Act, which governs 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 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 subjects owners of oil handling facilities to strict, joint and several liability 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 and natural resource damages. Although defenses exist to the liability imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to

17


 
 

TABLE OF CONTENTS

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.  In December 2009, the U.S. Environmental Protection Agency (the “EPA”) 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 regulates emissions of greenhouse gases from certain large stationary sources. 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, 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. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

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 497 employees at June 30, 2014, none of which were represented by labor unions or covered by any collective bargaining agreement. We believe that relations with our employees are good.

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.

18


 
 

TABLE OF CONTENTS

Item 1A. Risk Factors

Risks Related to Our Business

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

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

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;
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 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:

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.

19


 
 

TABLE OF CONTENTS

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.

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. For instance, on June 5, 2013, our interest in the Lafitte well effectively expired due to the need for a completion process that would have required the development of 30,000 psi equipment. The design development and procurement of such equipment would require an extended period of time leading up to the initiation of completion activities.

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

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.

Our financial condition, revenues, profitability and carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. Commodity prices also affect our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The markets for these commodities are volatile and even relatively modest drops in prices can affect our financial results and impede our growth.

20


 
 

TABLE OF CONTENTS

Natural gas and oil prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. For example, the WTI crude oil price per barrel for the period between January 1, 2014 and June 30, 2014 ranged from a high of $107.26 to a low of $91.66 and the NYMEX natural gas price per MMBtu for the period January 1, 2014 to June 30, 2014 ranged from a high of $6.15 to a low of $4.01. 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 productivity;
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.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower oil and natural gas prices may not only decrease our expected future revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in us having to make downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

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.

21


 
 

TABLE OF CONTENTS

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, 2014 prepared in a manner consistent with our interpretation of the SEC rules relating to modernizing reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent petroleum consultant 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, we may have to write off reserves previously recognized as proved undeveloped. During the year ended June 30, 2014, we were not required to reduce any proved reserve estimates due to the five year development rule.

As of June 30, 2014, approximately 39% of our total proved reserves were undeveloped and approximately 15% 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. We are not the operator of approximately 1% of our proved undeveloped reserves, so we may not be in a position to control the timing of all development activities. 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 finding or acquiring additional reserves. If we are unable to replace reserves through drilling or acquisitions, 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.

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

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

22


 
 

TABLE OF CONTENTS

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.

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 wells to date with our participations ranging from approximately 9% to 20%. 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, Viosca Knoll 822/823, Viosca Knoll 821, Viosca Knoll 1003 and Mississippi Canyon 248. The Mississippi Canyon 248 field was acquired in the EPL Acquisition. 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.

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, 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 Deep Water 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

23


 
 

TABLE OF CONTENTS

participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is severe, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, we do not intend to put in place business interruption insurance due to its high cost. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.

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

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

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

We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. 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.

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 on the day of the estimate. However, 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;

24


 
 

TABLE OF CONTENTS

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.

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.

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

Market conditions, 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.

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 currently operate approximately 96% of our proved reserves. 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;

25


 
 

TABLE OF CONTENTS

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 two customers.

Shell and ExxonMobil each accounted for approximately 45% and 43% of our total oil and natural gas revenues during the year ended June 30, 2014, respectively. Our inability to continue to sell our production to Shell or ExxonMobil, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.

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.

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

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

26


 
 

TABLE OF CONTENTS

Write-downs may be required in the full cost ceiling and goodwill recorded in connection with our oil and natural gas properties acquisition if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows.

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, 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.

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

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

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

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

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

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

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;

27


 
 

TABLE OF CONTENTS

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;
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.

Risks Related to Our Risk Management Activities

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 natural gas and oil price volatility on our cash flow from operations. Currently, we use a combination of natural gas and crude oil put, swap and collar arrangements to mitigate the volatility of future natural gas and oil 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

28


 
 

TABLE OF CONTENTS

certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:

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.

Risks Related to Our Acquisition Strategy

Our acquisitions may be stretching our existing resources.

Since our inception in July 2005, we have made six major acquisitions and have become a reporting company in the U.S. Most recently, on June 3, 2014, we completed the acquisition of EPL. We expect to incur substantial expenses in connection with the integration of Energy XXI and EPL. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated, including purchasing, accounting and finance, sales, billing, payroll, pricing, revenue management, maintenance, marketing, payments triggered by change in control provisions and benefits. While Energy XXI and EPL have assumed that a certain level of expenses would be incurred, there are many factors beyond their control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These expenses could, particularly in the near term, exceed the savings that the combined company expects to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings. These integration expenses likely will result in the combined company taking significant charges against earnings following the completion of the EPL Acquisition.

Future transactions may also prove to stretch our internal resources and infrastructure. As a result, we may need to invest in additional resources, which will increase our costs. Any further acquisitions we make over the short term would likely intensify these risks.

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.

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.

29


 
 

TABLE OF CONTENTS

For example, the EPL Acquisition involves the integration of two companies that had operated independently. The success of the EPL Acquisition will depend, in large part, on our ability to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the businesses of Energy XXI and EPL. To realize these anticipated benefits, the businesses of Energy XXI and EPL must be successfully integrated. This integration will be complex and time-consuming. The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the EPL Acquisition.

Potential difficulties that may be encountered in the integration process include the following:

the inability to successfully integrate the businesses of Energy XXI and EPL in a manner that permits the combined company to achieve the full benefit of synergies, cost savings and operational efficiencies that are anticipated to result from the EPL Acquisition;
complexities associated with managing the larger, more complex, combined business;
complexities associated with integrating the workforces of the two companies;
potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the EPL Acquisition, including one-time cash costs to integrate the two companies that may exceed the anticipated range of such one-time cash costs that Energy XXI and EPL estimated as of the date of execution of the EPL Acquisition Agreement;
difficulty or inability to refinance the debt of the combined company or comply with the covenants thereof;
performance shortfalls at one or both of the companies as a result of the diversion of management’s attention caused by completing the EPL Acquisition and integrating the companies’ operations; and
the disruption of, or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies.

Any of these difficulties in successfully integrating the businesses of Energy XXI and EPL, or any delays in the integration process, could adversely affect our ability to achieve the anticipated benefits of the EPL Acquisition and could adversely affect our business, financial results, financial condition and stock price. Even if we are able to integrate the business operations of Energy XXI and EPL successfully, there can be no assurance that this integration will result in the realization of the full benefits of synergies, cost savings, innovation and operational efficiencies that we currently expect from this integration or that these benefits will be achieved within the anticipated time frame.

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.

For example, following the EPL Acquisition, our size increased significantly beyond the size of either Energy XXI’s or EPL’s business prior to the EPL Acquisition. Our future success depends, in part, upon our ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that we will be successful or that we will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the EPL Acquisition.

30


 
 

TABLE OF CONTENTS

If we are unable to effectively manage the commodity price risk of our production if energy prices fall, we may not realize the anticipated cash flows from our acquisitions.

Compared to some other participants in the oil and gas industry, we are a relatively small company with modest resources. Therefore, there is the possibility that we may be unable to find counterparties willing to enter into derivative arrangements with us or be required to either purchase relatively expensive put options, or commit to deliver future production, to manage the commodity price risk of our future production. To the extent that we commit to deliver future production, we may be forced to make cash deposits available to counterparties as they mark to market these financial hedges. Proposed changes in regulations affecting derivatives may further limit or raise the cost, or increase the credit support required to hedge. This funding requirement may limit the level of commodity price risk management that we are prudently able to complete. In addition, we are unlikely to hedge undeveloped reserves to the same extent that we hedge the anticipated production from proved developed reserves. If we fail to manage the commodity price risk of our production and energy prices fall, we may not be able to realize the cash flows from our assets that are currently anticipated even if we are successful in increasing the production and ultimate recovery of reserves.

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.

Risks Related to Our Indebtedness and Access to Capital and Financing

Our level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities.

As of June 30, 2014, we had total indebtedness of $3,760 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;

31


 
 

TABLE OF CONTENTS

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;
have a material adverse effect if we fail to comply with financial and restrictive covenants in any of our debt agreements, including an event of default if such event is not cured or waived;
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.

If we are unable to meet future debt service obligations and other financial obligations, we could be forced to restructure or refinance our indebtedness and other financial transactions, seek additional equity or sell assets. We may then be unable to obtain such financing or capital or sell assets on satisfactory terms, if at all.

We and our subsidiaries may be able to incur substantially more debt. This could further increase our leverage and attendant risks.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indentures governing our senior notes and our revolving credit facility do not fully prohibit us or our subsidiaries from doing so. At June 30, 2014, we and our subsidiaries collectively had approximately $716.1 million of secured indebtedness and $3.0 billion of other indebtedness. If new debt or liabilities are added to our current debt level, the related risks that we now face could increase.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures and development and exploration efforts will depend on our ability to generate cash in the future. Our future operating performance and financial results will be subject, in part, to factors beyond our control, including interest rates and general economic, financial and business conditions. We cannot assure that our business will generate sufficient cash flow from operations or that future borrowings or other facilities will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs.

If we are unable to generate sufficient cash flow to service our debt, we may be required to:

refinance all or a portion of our debt;
obtain additional financing;
sell some of our assets or operations;
reduce or delay capital expenditures, research and development efforts and acquisitions; or
revise or delay our strategic plans.

If we are required to take any of these actions, it could have a material adverse effect on our business, financial condition and results of operations. In addition, we cannot assure that we would be able to take any of these actions, that these actions would enable us to continue to satisfy our capital requirements or that these actions would be permitted under the terms of our various debt instruments.

32


 
 

TABLE OF CONTENTS

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.

The indentures governing our senior notes and our revolving credit facility contain various covenants that limit our ability and the ability of our subsidiaries to, among other things:

incur certain payment obligations;
incur indebtedness and issue preferred stock; and
sell or otherwise dispose of assets, including capital stock of subsidiaries.

The existence of these covenants may prevent or delay us from pursuing business opportunities that we believe would otherwise benefit us. For example, as of June 30, 2014, EGC anticipates it may not have been in compliance with the total leverage ratio covenant included within Section 7.2.4(a) of the First Lien Credit Agreement, which requires EGC to maintain a Total Leverage Ratio (as defined therein) of not more than 3.5 to 1.0 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC’s leverage ratio was 3.6 to 1.0 for the quarter ended June 30, 2014. EGC received a waiver from the lenders under the First Lien Credit Agreement on August 22, 2014 with respect to this violation for the quarters ending June 30, 2014 and September 30, 2014. The waiver is conditioned upon EGC maintaining a Total Leverage Ratio of not more than 4.25 to 1.00 for each of the fiscal quarters ending June 30, 2014 and September 30, 2014. EGC was in compliance with the requirements under the waiver for the fiscal quarter ended June 30, 2014 and expects to be in compliance therewith for the fiscal quarter ended September 30, 2014. EGC is currently in discussions with the lenders under the First Lien Credit Agreement to amend certain of the financial covenants in order to ensure that EGC will be in compliance with the covenants for the remainder of the 2015 fiscal year. There is no assurance that EGC will reach agreement with its lenders on these amendments. In the event an amendment cannot be obtained, EGC may need to take certain actions within its control in order to comply with the current covenants.

In addition, if we breach any of these covenants, a default could occur. A default, if not waived, would entitle certain of our debt holders to declare all amounts borrowed under the breached indenture to become immediately due and payable, which could also cause the acceleration of obligations under certain other agreements and the termination of our credit facility. In the event of acceleration of our outstanding indebtedness, 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.

The indenture governing the 8.25% senior notes due 2018 includes restrictive covenants, which could adversely affect the future business and operations of the combined company.

The covenants included in the indenture governing the 8.25% senior notes due 2018 (“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. In the event that we are unable to obtain the requisite consents for an amendment or are unable to replace or refinance the 8.25% Senior Notes, the notes’ restrictive covenants could make it more difficult to integrate the operations of Energy XXI and EPL and operate the combined company in the most efficient manner. Our failure in this regard could adversely affect our future business and operations.

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 for the acquisition, development, production, exploration and abandonment of oil and gas properties. Our capital requirements depend on numerous factors and we cannot predict accurately the timing and amount of our capital requirements. We intend to primarily finance our capital expenditures through cash flow from operations. However, 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.

33


 
 

TABLE OF CONTENTS

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.

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.

As of June 30, 2014, we had borrowed $689 million and had $225.7 million in letters of credit issued under our revolving credit facility and our borrowing base was $1.5 billion. We expect that the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2014. 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.

Our borrowing base is redetermined semi-annually by our lenders in their sole discretion. 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. 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. If oil and natural gas commodity prices deteriorate, the revised borrowing base under our revolving credit facility may be reduced. As a result, we may be unable to obtain adequate funding under our revolving credit facility or even be required to pay down amounts outstanding under our revolving credit facility to reduce our level of borrowing. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our exploration and development plans as currently anticipated and our ability to make new acquisitions, each of which could have a material adverse effect on our production, revenues and results of operations.

The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of all the lenders. 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 unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.

34


 
 

TABLE OF CONTENTS

Any future financial crisis may impact our business and financial condition. We may not be able to obtain funding in the capital markets on terms we find acceptable, or obtain funding under our revolving credit facility because of the deterioration of the capital and credit markets and our borrowing base.

The recent credit crisis and related turmoil in the global financial systems had an impact on our business and our financial condition, and we may face challenges if economic and financial market conditions deteriorate in the future. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures and have relied on the capital markets to provide us with additional capital for large or exceptional transactions. A recurrence of the economic crisis could further reduce the demand for oil and natural gas and put downward pressure on the prices for oil and natural gas.

Our current borrowing base under our revolving credit facility is $1.5 billion. 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. Declines in commodity prices, or a continuing decline in those prices, could result in a determination to lower the borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base. The turmoil in the financial markets has adversely impacted the stability and solvency of a number of large global financial institutions.

The recent credit crisis also made it more difficult to obtain funding in the public and private capital markets. In particular, the cost of raising money in the debt and equity capital markets increased substantially while the availability of funds from those markets generally diminished significantly. Also, as a result of concerns about the general stability of financial markets and the solvency of specific counterparties, the cost of obtaining financing from the credit markets increased as many lenders and institutional investors increased interest rates, imposed tighter lending standards, refused to refinance existing debt at maturity or on terms similar to existing debt or at all, or, in some cases, ceased to provide any new funding. In recent years, access to capital has significantly improved and the cost of raising money in the debt capital markets has been near all-time lows. However, a return to the conditions seen during and after the crisis could materially and adversely affect our company.

Risks Related to Environmental and Other Regulations

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.

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

35


 
 

TABLE OF CONTENTS

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 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.

36


 
 

TABLE OF CONTENTS

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 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 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.

37


 
 

TABLE OF CONTENTS

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.

New regulatory requirements and permitting procedures recently imposed by the BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the April 2010 Deepwater Horizon incident in the Gulf of Mexico, federal authorities have pursued a series of regulatory initiatives to address the direct impact of that incident and to prevent similar incidents in the future. The federal government, acting through the U.S. Department of the Interior (“DOI”) and its implementing agencies that have since evolved into the present day BOEM and the BSEE, have issued various rules, Notices to Lessees and Operators (“NTLs”), and temporary drilling moratoria imposing new regulatory requirements and environmental and safety measures upon exploration, development and production operators in the Gulf of Mexico. These new regulatory requirements include the following:

The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.
The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.
The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.
The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

These regulatory initiatives may serve to effectively slow down the pace of drilling and production operations in the Gulf of Mexico due to adjustments in operating procedures and certification practices as well as increased lead times to obtain exploration and production plan reviews, develop drilling applications, and apply for and receive new well permits. The new rules also increase the cost of preparing each permit application and will increase the cost of each new well, particularly for wells drilled in deeper waters on the OCS. The Workplace Safety Rule also has the potential to increase the cost of operating existing wells. In addition, we could become subject to fines, penalties or orders requiring us to modify or suspend our operations in the Gulf of Mexico if we fail to comply with these requirements. Moreover, if oil spill incidents similar to the April 2010 Deepwater Horizon incident were to occur in the future in areas where we conduct operations, the United States or other countries could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue safety and environmental regulatory initiatives regarding offshore oil and gas exploration and development activities, which any one or more of such events could have a material adverse effect on our volume of business, our financial position, our results of operations, and liquidity.

38


 
 

TABLE OF CONTENTS

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

Lastly, it is expected that a new NTL related to the requirements for an exemption from supplemental bonding will be issued in late 2014 or early 2015 which is expected to impact the eligibility to receive a supplemental bonding waiver.

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.

39


 
 

TABLE OF CONTENTS

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.

In December 2009, the EPA 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 another regulates emissions of greenhouse gases from certain large stationary sources. 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, 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. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

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. 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

40


 
 

TABLE OF CONTENTS

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.

We and our subsidiaries may need to obtain bonds or other surety in order to maintain compliance with those regulations promulgated by the U.S. Bureau of Ocean Energy Management, which, if required, could be costly and reduce borrowings available under our bank credit facility.

To cover the various obligations of lessees on the OCS of the Gulf of Mexico, 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 have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. As a result of the recent bankruptcy of ATP Oil and Gas, the BOEM has indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators and may increase the amount of financial assurance required with respect to these obligations. While we believe that we are currently exempt from the supplemental bonding requirements of the BOEM, the BOEM could re-evaluate our plugging obligations and increase them which could cause us to lose our exemption. The cost of these bonds or other surety could be substantial and there is no assurance that bonds or other surety could be obtained in all cases. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letter 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. The cost of compliance with these supplemental bonding requirements could materially and adversely affect our financial condition, cash flows and results of operations.

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.

We may be taxed as a United States corporation.

We are 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. We do 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, we and our 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.

41


 
 

TABLE OF CONTENTS

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 2014 sent to Congress by President Obama on April 10, 2013, 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 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.

42


 
 

TABLE OF CONTENTS

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).

43


 
 

TABLE OF CONTENTS

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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.

Litigation Related to the Merger

In March and April, 2014, three alleged EPL stockholders (the “plaintiffs”) filed three separate class action lawsuits in the Court of Chancery of the State of Delaware on behalf of EPL stockholders against EPL, its directors, Energy XXI, Energy XXI Gulf Coast, Inc., a Delaware corporation and an indirect wholly owned subsidiary of Energy XXI (“OpCo”), and Clyde Merger Sub, Inc., a Delaware corporation and wholly owned subsidiary of OpCo (“Merger Sub” and collectively, the “defendants”). The Court of Chancery of the State of Delaware consolidated these lawsuits on May 5, 2014. The consolidated lawsuit is styled In re EPL Oil & Gas Inc. Shareholders Litigation, C.A. No. 9460-VCN, in the Court of Chancery of the State of Delaware (the “lawsuit”).

Plaintiffs allege a variety of causes of action challenging the Agreement and Plan of Merger between Energy XXI, OpCo, Merger Sub, and EPL (the “merger agreement”), which provides for the acquisition of EPL by Energy XXI. Plaintiffs allege that (a) EPL’s directors have allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL have allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs’ causes of action are based on their allegations that (i) the merger allegedly provided inadequate consideration to EPL stockholders for their shares of EPL common stock; (ii) the merger agreement contains contractual terms — including, among others, the (A) “no solicitation,” (B) “competing proposal,” and (C) “termination fee” provisions — that allegedly dissuaded other potential acquirers from making competing offers for shares of EPL common stock; (iii) certain of EPL’s officers and directors allegedly received benefits — including (A) an offer for one of EPL’s directors to join the Energy XXI board of directors and (B) the triggering of change-in-control provisions in notes held by EPL’s executive officers — that were not equally shared by EPL’s stockholders; (iv) Energy XXI required EPL’s officers and directors to agree to vote their shares of EPL common stock in favor of the merger; and (v) EPL provided, and Energy XXI obtained, non-public information that allegedly allowed Energy XXI to acquire EPL for inadequate consideration. Plaintiffs also allege that the Registration Statement filed on Form S-4 by EPL and Energy XXI on April 1, 2014 omits information concerning, among other things, (i) the events leading up to the merger, (ii) EPL’s efforts to attract offers from other potential acquirors, (iii) EPL’s evaluation of the merger; (iv) negotiations between EPL and Energy XXI, and (v) the analysis of EPL’s financial advisor. Based on these allegations, plaintiffs seek to have the merger agreement rescinded. Plaintiffs also seek damages and attorneys’ fees.

Defendants date to answer, move to dismiss, or otherwise respond to the lawsuit has been indefinitely extended. Neither Energy XXI nor EPL can predict the outcome of the lawsuit or any others that might be filed subsequent to the date of the filing of this quarterly report; nor can either Energy XXI or EPL predict the amount of time and expense that will be required to resolve the lawsuit. The defendants intend to vigorously defend the lawsuit.

Item 4. Mine Safety Disclosures

Not applicable.

44


 
 

TABLE OF CONTENTS

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 2013
                 
First Quarter   $ 37.37     $ 29.76  
Second Quarter     35.60       30.68  
Third Quarter     34.83       27.16  
Fourth Quarter     26.79       21.78  
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  

As of July 31, 2014, there were approximately 509 holders of record of our common stock.

Dividend Information

We paid quarterly cash dividends of $0.07 per share to holders of our common stock on September 14, 2012, December 14, 2012 and March 15, 2013 to shareholders of record on August 31, 2012, November 30, 2012 and March 1, 2013, respectively. We paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, to shareholders of record on May 31, 2013.

We paid quarterly cash dividends of $0.12 per share to holders of our common stock on September 13, 2013, December 13, 2013, March 14, 2014 and June 13, 2014 to shareholders of record on August 30, 2013, November 29, 2013 and February 28, 2014 and May 30, 2014, respectively.

On July 16, 2014, our Board of Directors approved payment of a quarterly cash dividend of $0.12 per share to the holders of our common stock. The quarterly dividend will be paid on September 12, 2014 to shareholders of record on August 29, 2014.

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.

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

45


 
 

TABLE OF CONTENTS

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 quarter ended June 30, 2014 and we have suspended the repurchase program indefinitely to reduce our capital needs.

46


 
 

TABLE OF CONTENTS

Item 6. Selected Financial Data

The selected consolidated financial data set forth below should be read in conjunction with Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and with the consolidated financial statements and notes to those consolidated financial statements included elsewhere in this Form 10-K.

         
  Year Ended June 30,
     2014   2013   2012   2011   2010
     (In Thousands, Except per Share Amounts)
Income Statement Data
                                            
Revenues   $ 1,230,725     $ 1,208,845     $ 1,303,403     $ 859,370     $ 498,931  
Depreciation, Depletion and Amortization (“DD&A”)     423,319       376,224       367,463       293,479       181,640  
Operating Income     280,411       361,805       483,284       208,923       102,047  
Other Income (Expense) – Net     (164,211 )      (113,091 )      (108,811 )      (132,006 )      (58,483 ) 
Net Income     59,111       162,081       335,827       64,655       27,320  
Basic Earnings per Common Share   $ 0.64     $ 1.90     $ 4.10     $ 0.42     $ 0.56  
Diluted Earnings per Common Share   $ 0.64     $ 1.86     $ 3.85     $ 0.42     $ 0.56  
Cash Flow Data
                                            
Provided by (Used in)
                                            
Operating Activities   $ 545,460     $ 638,148     $ 785,514     $ 387,725     $ 121,213  
Investing Activities
                                            
Acquisitions     (849,641 )      (161,164 )      (6,401 )      (1,012,262 )      (293,037 ) 
Investment in properties     (788,676 )      (816,105 )      (570,670 )      (281,233 )      (145,112 ) 
Other     93,742       (16,734 )      7,478       38,423       53,989  
Total Investing Activities     (1,544,575 )      (994,003 )      (569,593 )      (1,255,072 )      (384,160 ) 
Financing Activities     1,144,921       238,768       (127,241 )      881,530       188,246  
Increase (Decrease) in Cash   $ 145,806     $ (117,087 )    $ 88,680     $ 14,183     $ (74,701 ) 
Dividends Paid per Average Common Share   $ 0.48     $ 0.33     $ 0.07              

         
  June 30,
     2014   2013   2012   2011   2010
     (In Thousands)
Balance Sheet Data
                                            
Total Assets   $ 7,436,778     $ 3,611,711     $ 3,130,947     $ 2,798,860     $ 1,566,491  
Long-term Debt Including Current Maturities     3,759,644       1,370,045       1,018,344       1,113,387       774,600  
Stockholders’ Equity     1,797,830       1,437,246       1,405,840       946,697       436,561  
Common Shares Outstanding     93,720       76,486       78,838       76,203       50,637  

47


 
 

TABLE OF CONTENTS

         
  Year Ended June 30,
Operating Highlights   2014   2013   2012   2011   2010
     (In Thousands, Except per Unit Amounts)
Operating revenues
                                            
Crude oil sales   $ 1,104,206     $ 1,067,686     $ 1,186,193     $ 777,869     $ 383,928  
Natural gas sales     135,792       112,753       88,608       101,815       69,399  
Hedge gain (loss)     (9,273 )      28,406       28,602       (20,314 )      45,604  
Total revenues     1,230,725       1,208,845       1,303,403       859,370       498,931  
Percent of operating revenues from
crude oil
                                            
Prior to hedge gain (loss)     89 %      90 %      93 %      88 %      85 % 
Including hedge gain (loss)     89 %      89 %      91 %      84 %      78 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     31,183       32,737       28,521       27,876       27,603  
Workover and maintenance     66,481       65,118       56,413       33,095       19,630  
Direct lease operating expense     268,083       239,308       225,881       178,507       95,379  
Total lease operating expense     365,747       337,163       310,815       239,478       142,612  
Production taxes     5,427       5,246       7,261       3,336       4,217  
Gathering and transportation     23,532       24,168       16,371       12,499        
Depreciation, depletion and amortization     423,319       376,224       367,463       293,479       181,640  
General and administrative     96,402       71,598       86,276       75,091       49,667  
Other – net     35,887       32,641       31,933       26,564       18,748  
Total operating expenses     950,314       847,040       820,119       650,447       396,884  
Operating income   $ 280,411     $ 361,805     $ 483,284     $ 208,923     $ 102,047  
Sales volumes per day
                                            
Natural gas (MMcf)     89.7       88.6       81.5       67.2       42.6  
Crude oil (MBbls)     30.1       28.3       30.5       23.4       14.7  
Total (MBOE)     45.0       43.1       44.1       34.6       21.8  
Percent of sales volumes from crude oil     67 %      66 %      69 %      68 %      67 % 
Average sales price
                                            
Natural gas per Mcf   $ 4.15     $ 3.48     $ 2.97     $ 4.15     $ 4.47  
Hedge gain per Mcf     0.11       0.47       0.94       1.54       2.68  
Total natural gas per Mcf   $ 4.26     $ 3.95     $ 3.91     $ 5.69     $ 7.15  
Crude oil per Bbl   $ 100.59     $ 103.48     $ 106.17     $ 90.95     $ 71.73  
Hedge gain (loss) per Bbl     (1.18 )      1.29       0.04       (6.80 )      0.75  
Total crude oil per Bbl   $ 99.41     $ 104.77     $ 106.21     $ 84.15     $ 72.48  
Total hedge gain (loss) per BOE   $ (0.56 )    $ 1.81     $ 1.77     $ (1.61 )    $ 5.74  
Operating revenues per BOE   $ 74.88     $ 76.95     $ 80.74     $ 67.98     $ 62.83  
Operating expenses per BOE
                                            
Lease operating expense
                                            
Insurance expense     1.90       2.08       1.77       2.21       3.48  
Workover and maintenance     4.04       4.15       3.49       2.62       2.47  
Direct lease operating expense     16.31       15.23       13.99       14.12       12.01  
Total lease operating expense per BOE     22.25       21.46       19.25       18.95       17.96  
Production taxes     0.33       0.33       0.45       0.26       0.53  
Gathering and transportation     1.43       1.54       1.01       0.98        
Depreciation, depletion and amortization     25.75       23.95       22.76       23.22       22.87  
General and administrative     5.87       4.56       5.34       5.94       6.25  
Other – net     2.19       2.08       1.98       2.10       2.36  
Total operating expenses per BOE     57.82       53.92       50.79       51.45       49.97  
Operating income per BOE   $ 17.06     $ 23.03     $ 29.95     $ 16.53     $ 12.86  

48


 
 

TABLE OF CONTENTS

         
  Quarter Ended
Operating Highlights   June 30,
2014
  Mar. 31,
2014
  Dec. 31,
2013
  Sept. 30,
2013
  June 30,
2013
     (In Thousands, Except per Unit Amounts)
Operating revenues
                                            
Crude oil sales   $ 294,974     $ 254,641     $ 263,626     $ 290,965     $ 270,623  
Natural gas sales     34,508       37,562       31,138       32,584       38,630  
Hedge gain (loss)     (5,348 )      (7,020 )      2,052       1,043       5,072  
Total revenues     324,134       285,183       296,816       324,592       314,325  
Percent of operating revenues from
crude oil
                                            
Prior to hedge gain (loss)     90 %      87 %      89 %      90 %      88 % 
Including hedge gain (loss)     89 %      88 %      88 %      89 %      87 % 
Operating expenses
                                            
Lease operating expense
                                            
Insurance expense     8,357       6,410       7,920       8,496       7,462  
Workover and maintenance     14,408       17,797       19,690       14,586       15,622  
Direct lease operating expense     79,806       59,417       66,179       62,681       59,371  
Total lease operating expense     102,571       83,624       93,789       85,763       82,455  
Production taxes     1,750       1,090       1,189       1,398       1,481  
Gathering and transportation     6,509       5,700       5,978       5,345       5,668  
DD&A     119,691       99,899       103,513       100,216       96,846  
General and administrative     30,824       24,208       17,698       23,672       12,299  
Other – net     8,112       5,861       13,147       8,767       3,829  
Total operating expenses     269,457       220,382       235,314       225,161       202,578  
Operating income   $ 54,677     $ 64,801     $ 61,502     $ 99,431     $ 111,747  
Sales volumes per day
                                            
Natural gas (MMcf)     84.8       83.7       89.3       100.8       107.4  
Crude oil (MBbls)     32.0       28.4       30.2       29.7       28.9  
Total (MBOE)     46.1       42.3       45.1       46.6       46.8  
Percent of sales volumes from crude oil     69 %      67 %      67 %      64 %      62 % 
Average sales price
                                            
Natural gas per Mcf   $ 4.47     $ 4.98     $ 3.79     $ 3.51     $ 3.95  
Hedge gain (loss) per Mcf     (0.02 )      (0.31 )      0.42       0.30       0.23  
Total natural gas per Mcf   $ 4.45     $ 4.67     $ 4.21     $ 3.81     $ 4.18  
Crude oil per Bbl   $ 101.45     $ 99.71     $ 94.85     $ 106.31     $ 102.82  
Hedge gain (loss) per Bbl     (1.78 )      (1.83 )      (0.50 )      (0.63 )      1.08  
Total crude oil per Bbl   $