UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended June 30, 2015
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number:001-33628
Energy XXI Ltd
(Exact name of registrant as specified in its charter)
Bermuda | 98-0499286 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
Canon’s Court, 22 Victoria Street, PO Box HM 1179, Hamilton HM EX, Bermuda | N/A | |
(Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code:(441)-295-2244
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |
Common Stock, par value $0.005 per share | NASDAQ Global Select Market |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yeso Nox
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.Yeso Nox
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.Yesx Noo
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).Yesx Noo
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 filero | Accelerated filerx | |
Non-accelerated filero | Smaller reporting companyo | |
(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).Yeso Nox
The aggregate market value of the registrant’s common stock held by non-affiliates was approximately $224,982,321 based on the closing sale price of $3.26 per share as reported on The NASDAQ Global Select Market on December 31, 2014, the last business day of the registrant’s most recently completed second fiscal quarter.
The number of shares of the registrant’s common stock outstanding on September 18, 2015 was 94,966,655.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrant’s definitive proxy statement for its 2015 Annual Meeting of Shareholders, which will be filed within 120 days of June 30, 2015, are incorporated by reference into Part III of this Annual Report on Form 10-K.
TABLE OF CONTENTS
Page | |||||
GLOSSARY OF TERMS | ii | ||||
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS | i | ||||
PART I | |||||
Item 1 Business | 3 | ||||
Item 1A Risk Factors | 22 | ||||
Item 1B Unresolved Staff Comments | 47 | ||||
Item 2 Properties | 47 | ||||
Item 3 Legal Proceedings | 48 | ||||
Item 4 Mine Safety Disclosures | 48 | ||||
PART II | |||||
Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 49 | ||||
Item 6 Selected Financial Data | 51 | ||||
Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations | 55 | ||||
Item 7A Quantitative and Qualitative Disclosures About Market Risk | 84 | ||||
Item 8 Financial Statements and Supplementary Data | 87 | ||||
Item 9 Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 287 | ||||
Item 9A Controls and Procedures | 287 | ||||
Item 9B Other Information | 289 | ||||
PART III | |||||
Item 10 Directors, Executive Officers and Corporate Governance | 289 | ||||
Item 11 Executive Compensation | 289 | ||||
Item 12 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 289 | ||||
Item 13 Certain Relationships and Related Transactions, and Director Independence | 289 | ||||
Item 14 Principal Accounting Fees and Services | 290 | ||||
PART IV | |||||
Item 15 Exhibits, Financial Statement Schedules | 290 | ||||
Signatures | 296 |
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GLOSSARY OF TERMS
Below is a list of terms that are common to our industry and used throughout this Annual Report on Form 10-K:
Bbls | Standard barrel containing 42 U.S. gallons | MMBbls | One million Bbls | |||
Mcf | One thousand cubic feet | MMcf | One million cubic feet | |||
Btu | One British thermal unit | MMBtu | One million Btu | |||
BOE | Barrel of oil equivalent. Natural gas is converted into one BOE based on six Mcf of gas to one barrel of oil | MBOE | One thousand BOEs | |||
DD&A | Depreciation, Depletion and Amortization | MMBOE | One million BOEs | |||
Bcf | One billion cubic feet |
Call options are contracts giving the holder (purchaser) the right, but not the obligation, to buy (call) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).
Completion refers to the work performed and the installation of permanent equipment for the production of natural gas and/or crude oil from a recently drilled or recompleted well.
Development well is a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry Well is an exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Exploitation is drilling wells in areas proven to be productive.
Exploratory well is a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well or a service well.
Field is an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. For a complete definition of a field, refer to Rule 4-10(a)(8) of Regulation S-X as promulgated by the Securities and Exchange Commission (“SEC”).
Formation is a stratum of rock that is recognizable from adjacent strata consisting mainly of a certain type of rock or combination of rock types with thickness that may range from less than two feet to hundreds of feet.
Gathering and transportation is the cost of moving crude oil from several wells into a single tank battery or major pipeline.
Gross acres or gross wells are the total acres or wells in which a working interest is owned.
Horizon is a zone of a particular formation or that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.
Independent oil and gas company is a company that is primarily engaged in the exploration and production sector of the oil and gas business.
Lease operating or well operating expenses are expenses incurred to operate the wells and equipment on a producing lease.
Net acreage and net oil and gas wells are obtained by multiplying gross acreage and gross oil and gas wells by the fractional working interest owned in the properties.
Oil includes crude oil, condensate and natural gas liquids.
Operating costs include direct and indirect expenses, including general and administrative expenses, incurred to manage, operate and maintain wells and related equipment and facilities.
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Plugging and abandonment refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from a stratum will not escape into another or to the surface. Regulations of many states and the federal government require the plugging of abandoned wells.
Production costs are costs incurred to operate and maintain our wells and related equipment and facilities. For a complete definition of production costs, please refer to Rule 4-10(a)(20) of Regulation S-X as promulgated by the SEC.
Productive well is an exploratory, development or extension well that is not a dry well.
Proved area refers to the part of a property to which proved reserves have been specifically attributed.
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. For a complete definition of proved reserves, refer to Rule 4-10(a)(22) of Regulation S-X as promulgated by the SEC.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. For a complete definition of proved developed oil and gas reserves, refer to Rule 4-10(a)(3) of Regulation S-X as promulgated by the SEC.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. For a complete definition of proved undeveloped oil and gas reserves, refer to Rule 4-10(a)(4) of Regulation S-X as promulgated by the SEC.
Put options are contracts giving the holder (purchaser) the right, but not the obligation, to sell (put) a specified item at a fixed price (exercise or strike price) during a specified period. The purchaser pays a nonrefundable fee (the premium) to the seller (writer).
Reserve acquisition cost The total consideration paid for an oil and natural gas property or set of properties, which includes the cash purchase price and any value ascribed to units issued to a seller adjusted for any post-closing items.
Reservoir refers to a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Seismic is an exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formations. 2-D seismic provides two-dimensional information and 3-D seismic provides three-dimensional pictures.
Working interest is the operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover is the operations on a producing well to restore or increase production and such costs are expensed. If the operations add new proved reserves, such costs are capitalized.
Zone is a stratigraphic interval containing one or more reservoirs.
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Certain statements and information in this Annual Report on Form 10-K (this “Form 10-K) may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances and their potential effect on us. While management believes that these forward-looking statements are reasonable, such statements are not guarantees of future performance and the actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to those summarized below:
• | our business strategy; |
• | further or sustained declines in the prices we receive for our oil and gas production; |
• | our future financial condition, results of operations, revenues, cash flows and expenses; |
• | our future levels of indebtedness, liquidity and compliance with debt covenants; |
• | our inability to obtain additional financing necessary to fund our operations, capital expenditures, and to meet our other obligations; |
• | economic slowdowns that can adversely affect consumption of oil and gas by businesses and consumers; |
• | uncertainties in estimating our oil and gas reserves and net present values of those reserves; |
• | the need to take ceiling test impairments due to lower commodity prices; |
• | hedging activities exposing us to pricing and counterparty risks; |
• | replacing our oil and gas reserves; |
• | geographic concentration of our assets; |
• | uncertainties in exploring for and producing oil and gas, including exploitation, development, drilling and operating risks; |
• | our ability to make acquisitions and to integrate acquisitions; |
• | our ability to establish production on our acreage prior to the expiration of related leaseholds; |
• | availability of drilling and production equipment, facilities, field service providers, gathering, processing and transportation; |
• | disruption of operations and damages due to capsizing, collisions, hurricanes or tropical storms; |
• | environmental risks; |
• | availability, cost and adequacy of insurance coverage; |
• | competition in the oil and gas industry; |
• | our inability to retain and attract key personnel; |
• | the effects of government regulation and permitting and other legal requirements; |
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• | costs associated with perfecting title for mineral rights in some of our properties; and |
• | weakness in our internal controls. |
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please read (1) Part I, Item 1A. “Risk Factors” and elsewhere in this Form 10-K, (2) our reports and registration statements filed from time to time with the Securities and Exchange Commission and (3) other public announcements we make from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date upon which they are made, whether as a result of new information, future events or otherwise.
EXPLANATORY NOTE — RESTATEMENT OF FINANCIAL INFORMATION
In connection with preparing this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues. As a result, we concluded that certain of our previously issued consolidated financial statements should no longer be relied upon and would need to be restated.
This Form 10-K for the year ended June 30, 2015 includes (1) a restated balance sheet as of June 30, 2014, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended June 30, 2014 and 2013, (3) restated quarterly consolidated financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, March 31, 2015 and 2014, (4) restated quarterly consolidated financial information for the quarter ended June 30, 2014, and (5) restated selected financial data for the years ended June 30, 2014, 2013, 2012, and 2011. See Item 6, “Selected Financial Data,” Item 8, “Financial Statements and Supplementary Data,” and Item 9A, “Controls and Procedures,” in Part II of this Form 10-K, including Notes 22 and 23 of the notes to the Consolidated Financial Statements, for more information concerning these restatements. The consolidated financial statements for prior periods presented in this report have been restated primarily to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) as gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling tests, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement.
We do not plan to amend previously filed reports in connection with the restatement. The consolidated financial statements that have been previously filed or otherwise reported for these periods are superseded by the information in this Form 10-K. Unless otherwise stated, all financial and accounting information contained in this Form 10-K is presented on a restated basis.
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PART I
Item 1. Business
Overview
Energy XXI Ltd, including its wholly-owned subsidiaries (“Energy XXI,” “us,” “we,” “our,” or “the Company”), is an independent oil and natural gas exploration and production company. We were originally formed and incorporated in July 2005 as an exempted company under the laws of Bermuda to serve as a vehicle for the acquisition of oil and gas reserves and related assets. In October 2005, we completed a $300 million initial public offering of our common stock and warrants on the Alternative Investment Market of the London Stock Exchange (“AIM”). On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market, and on August 12, 2011, our common stock was admitted for trading on the Nasdaq Global Select Market (“NASDAQ”) under the symbol “EXXI.”
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to AIM. We successfully delisted from AIM on December 15, 2014.
With our principal operating subsidiary headquartered in Houston, Texas, we are engaged in the acquisition, development, operation and exploration of oil and natural gas properties onshore in Louisiana and Texas and on the Gulf of Mexico Shelf (“GoM Shelf”). Based on production volume, we are the largest publicly traded independent operator on the GoM Shelf.
Since our inception in 2005, we have completed six major acquisitions for aggregate cash consideration of approximately $5.0 billion. In February 2006, we acquired Marlin Energy, L.L.C. (“Marlin”) for total cash consideration of approximately $448.4 million. In June 2006, we acquired Louisiana Gulf Coast producing properties from affiliates of Castex Energy, Inc. (“Castex”) for approximately $312.5 million in cash (the “Castex Acquisition”). In June 2007, we purchased certain GoM Shelf properties (the “Pogo Properties”) from Pogo Producing Company (“Pogo”) for approximately $415.1 million (the “Pogo Acquisition”). In November 2009, we acquired certain GoM Shelf oil and natural gas interests from MitEnergy Upstream LLC (“MitEnergy”), a subsidiary of Mitsui & Co., Ltd., for total cash consideration of $276.2 million (the “Mit Acquisition”). On December 17, 2010, we acquired certain shallow-water GoM Shelf oil and natural gas interests from affiliates of Exxon Mobil Corporation (“ExxonMobil”) for cash consideration of $1.01 billion (the “ExxonMobil Acquisition”). On June 3, 2014, we completed the acquisition of EPL Oil & Gas, Inc. (“EPL”) for approximately $2.5 billion, including the assumption of debt (the “EPL Acquisition”). The assets acquired in the EPL Acquisition are located on the GoM Shelf. Please see Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Form 10-K for detailed information on the EPL Acquisition.
Our acquisitions have been primarily oil-focused at an average reserve acquisition cost of approximately $21.35 per barrel of oil equivalent (“BOE”) and have provided us access to 742,197 net acres, ownership in 258 blocks, existing infrastructure to facilitate our growth and 16,766 square miles of 3D seismic data. We own and operate 9 of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor and thus increase the total oil recovered. The techniques utilized by us include:
• | reviewing historical files to identify situations where partially depleted or overlooked reservoirs were determined to be uneconomic and abandoned in previous lower price environments but which now offer economic exploitation opportunities in the current price environment; |
• | performing field studies, reservoir simulations and other analysis to identify previously overlooked, missed or under-appreciated opportunities to recover incremental oil reserves; |
• | drilling horizontal wells that enable us to recover a higher percentage of the original oil in place per well drilled versus a vertical well by providing for a more efficient sweep mechanism that minimizes water coning; |
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• | optimizing gas lift and other standard production techniques to optimize recovery from existing wellbores; |
• | utilizing reprocessed 3D seismic and Wide Azimuth (“WAZ”) seismic data to better image near salt domes and improve production at existing wellbores and identify new opportunities where we can drill closer to salt domes to recover additional oil; and |
• | injecting water through dump floods or water injection wells to increase reservoir pressure and facilitate moving additional water through the reservoir to sweep incremental oil. |
The above techniques enable us to continually identify new oil weighted opportunities and maintain a large inventory of exploitation opportunities while continuing to drill in these prolific large oil reservoirs.
Our geographic concentration on the GoM Shelf enables us to realize service cost synergies. By having operations in a geographically concentrated area, we can optimize helicopter and boat charters to more efficiently service our operations. In addition, our size provides us opportunities to place service work out to bid to obtain better services and prices.
As of June 30, 2015, our estimated net proved reserves were 183.5 MMBOE, of which 75% was oil and 68% was proved developed. Natural gas liquids comprised 5% of our oil reserves. Production for the first fiscal quarter of 2016 is averaging 58,300 BOE per day, of which 71% is oil.
Business Strategy
Our goal is to strengthen our position as the largest publicly traded independent operator on the GoM Shelf, with a focus on delivering value for our shareholders. We are focused on developing high quality oil-producing assets with low production decline rates. During the second quarter of fiscal year 2015, oil prices began a substantial and rapid decline which has continued into the fiscal year 2016. In response to that decline, we initiated a series of financial and operational activities highlighted below.
• | Our fiscal year 2016 capital budget has been substantially reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million, and our fiscal year 2016 budget is focused on recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success, and eliminating capital commitments on exploration and other activities that do not provide incremental production. |
• | We have reduced field level operating costs, bringing lease operating costs per barrel down by approximately 30% from fourth quarter of fiscal year 2014, and we have reduced general and administrative costs per barrel by approximately 36% from fourth quarter of fiscal year 2014 primarily through efficiencies and headcount reductions and continue to focus on operational and cost efficiencies. |
• | We have suspended dividends on our common stock for the foreseeable future. |
• | On March 12, 2015, we closed our private placement of $1.45 billion in aggregate principal amount of the 11.0% Senior Secured Second Lien Notes due 2020 (the “11.0% Notes”) for net proceeds of $1.35 billion, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our revolving credit facility to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016. |
• | In connection with the issuance of the 11.0% Notes, we amended our revolving credit facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants. |
• | On June 30, 2015, we sold the Grand Isle Gathering System (“GIGS”) for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the |
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decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor, a subsidiary of CorEnergy Infrastructure Trust, Inc., pursuant to which we will continue to operate the GIGS. |
• | In addition, on June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. |
• | During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices, which will provide us some price protection against further decline in oil prices. Subsequent to these transactions, we have some price protection under our hedging portfolio on approximately 27,000 barrels of crude oil per day representing approximately 70% of our estimated crude oil production volumes through December 2015 and some price protection on approximately 14,000 barrels of crude oil per day representing approximately 40% of our estimated crude oil production volumes in calendar 2016 under our hedging portfolio, which includes financially settled puts, put spreads, zero-cost collars and three-way collars. See Note 10 — “Derivative Financial Instruments” to our Consolidated Financial Statements in this Form 10-K for a detailed discussion of our hedging program. |
Due to the uncertainty regarding future commodity prices, we plan to manage our operating activities and financial liquidity carefully. We expect to fund the current fiscal year 2016 capital program with cash on hand and operating cash flow. We do not expect production from our fiscal year 2016 capital program to entirely offset production declines, resulting in slight decreases to our production and related cash flows. We plan to continuously evaluate our level of operating activity in light of both actual commodity prices and changes we are able to make to our costs of operations and make further adjustments to our capital spending program as appropriate, including potentially expanding our development drilling as commodity prices rebound. In addition, we expect to continue to regularly review acquisition opportunities, and we intend to evaluate and pursue potential asset sales of non-core assets to generate additional liquidity. Our acquisition strategy is to target mature, oil-producing properties on the GoM Shelf and the U.S. Gulf Coast that have not been thoroughly exploited by prior operators. We believe these activities will provide us with an inventory of low-risk recompletion and extension opportunities in our geographic area of expertise.
In addition, in light of current commodity prices and our leverage position, we continue to analyze a variety of transactions and mechanisms designed to reduce debt, including the retirement or purchase of outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
Business Strengths
To effectively execute our business strategy, we have assembled a team of engineers with an average of 19 years of industry experience and a team of geologic and geophysical experts with an average of 34 years of industry experience. Our technical staff has specific expertise in developing our core properties. Additionally, the members of our senior management team average 35 years of operating experience on the GoM Shelf.
Due to significant technological advancements in drilling and completion techniques, we believe our high percentage of oil reserves compared to our overall reserve base provides us with an economic advantage
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and enhances shareholder value. Additionally, the production decline curve for oil in our GoM Shelf fields is typically lower than a comparable natural gas decline curve, resulting in longer term production of current reserves.
All our assets are located on the U.S. Gulf Coast or on the GoM Shelf and we currently operate 97% of our proved reserves. As the operator of a property, we are afforded greater control of the optimization of production, the timing and amount of capital expenditures and the costs of our projects.
General Information on Properties
Below are descriptions of our significant properties at June 30, 2015. These properties represent approximately 81% of our net proved reserves and are ranked based on highest proved reserves as of June 30, 2015.
West Delta 73 Field. We operate and have a 100% working interest in the West Delta 73 field, located 28 miles offshore of Grand Isle, Louisiana in approximately 175 feet of water on the OCS. The field, which was first discovered in 1962 by Humble Oil and Refining, is a large low relief faulted anticline. The field produces from Pleistocene through Upper Miocene aged sands trapped structurally on the high side closures over the large anticlinal feature from 1,500 feet to 13,000 feet. The field has produced in excess of 384 MMBOE. There are seven production platforms and 44 active wells located throughout the field. The field’s net production for the month of June 2015 of 6.7 MBOE/Day (“MBOED”) accounted for approximately 11% of our net production. Net proved reserves for the field, which is our largest field based upon net proved reserves, were 86% oil at June 30, 2015.
West Delta 30 Field. We operate and have a 100% working interest in the West Delta 27, 28, 29 and 30 blocks, located 21 miles offshore of Grand Isle, Louisiana in approximately 45 feet of water on the Outer Continental Shelf (“OCS”). Blocks 27, 28 and 29 were acquired through the EPL Acquisition. The field, which was discovered in 1948 by Humble Oil and Refining, is a large salt dome. Productive sands range from 2,000 feet to 17,500 feet in depth and generally produce via strong water drive. Minor faulting that is secondary to the major normal fault separates hydrocarbon accumulations into compartments. The field has produced in excess of 746 MMBOE. There are 45 production structures and 98 active wells located throughout the field. The field’s net production for the month of June 2015 of 7.7 MBOED accounted for approximately 13% of our net production. Net proved reserves for the field were 84% oil at June 30, 2015. This field is the third largest oil field on the GoM Shelf, based on cumulative production to date.
South Timbalier 54 Field. We operate and have a 100% working interest in the South Timbalier 54 field, located 36 miles offshore of Lafourche Parish, Louisiana in approximately 67 feet of water on the OCS. The field was originally discovered in 1955 by Humble Oil and Refining. The field is at the confluence of regional and counter-regional fault systems. Pleistocene through Miocene sands are trapped from 4,800 feet to 17,000 feet in shallow low relief structures over a deeper seated salt dome and in combinations of structural and stratigraphic traps against salt at depth. Minor faulting separates hydrocarbon accumulations into individual compartments. The field has produced in excess of 149 MMBOE. There are six production platforms and 28 active wells located throughout the field. The field’s net production for the month of June 2015 of 3.2 MBOED accounted for approximately 5% of our net production. Net proved reserves for the field were 71% oil at June 30, 2015.
Main Pass 61 Field. We operate and have a 100% working interest in the Main Pass 61 field, located near the mouth of the Mississippi River in approximately 90 feet of water on OCS blocks Main Pass 60, 61, 62 and 63. The field was discovered by Pogo in 2000, and has produced in excess of 63 MMBOE since production first began in 2002, from four Upper Miocene sands. The primary producer is the J-6 Sand, which consists of a series of stratigraphic traps, located along a regional south dip. The two larger J-6 Sand stratigraphic pods are oil reservoirs that are being waterflooded to maximize recovery. There are 34 producing wells and three major production platforms located throughout the field. The field’s net production for the month of June 2015 of 7.0 MBOED accounted for approximately 12% of our net production. Net proved reserves for the field were 86% oil at June 30, 2015.
Ship Shoal 208 Field. We operate and have a 100% working interest in the Ship Shoal 208 Field, located 110 miles southwest of New Orleans, Louisiana in approximately 100 feet of water on OCS blocks
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Ship Shoal 208, 209 and 215. The field was acquired through the EPL Acquisition. The Ship Shoal 208 Field surrounds a large salt dome and produces from over 30 Upper Pliocene through Upper Miocene reservoirs. The field was discovered by Kerr-McGee Corporation in 1961 and has produced in excess of 455 MMBbls and 1,300 BCF since production first began in 1963. We have 13 platforms and 31 active wells throughout the field. The field’s net production for the month of June 2015 of 4.8 MBOED accounted for approximately 8% of our net production. Net proved reserves for the field were 70% oil at June 30, 2015.
South Pass 49 Field. We operate and have a 100% working interest in the South Pass 49 field, which is located near the mouth of the Mississippi River in approximately 400 feet of water. Additional interest in the field was acquired through the EPL Acquisition. The field was discovered by Gulf Oil in 1974. The field produces from Lower Pliocene sands, which consist of the Discorbis 20 thru Discorbis 70 sands, ranging in depths from 7,600 feet to 9,400 feet, on OCS blocks South Pass 33, 48, and 49. There are 14 active wells located throughout the field. The field is produced from one central production platform and has produced in excess of 121 MMBOE. The field’s net production for the month of June 2015 of 4.6 MBOED accounted for approximately 8% of our net production. Net proved reserves for the field were 62% oil at June 30, 2015.
South Pass 78. We operate and have 100% working interest in the South Pass 78 complex. Additional interest in the field was acquired through the EPL Acquisition. The complex is located 86 miles southeast of New Orleans. It contains 31 producing wells in water depths ranging from approximately 140 to 190 feet in four lease blocks. The field was discovered in 1972 by Pennzoil Energy Co. and has produced in excess of 253 MMBOE. There are four major production platforms, three of which have producing wells, located throughout the field. The field’s net production for the month of June 2015 of 4.2 MBOED accounted for approximately 7% of our net production. Net proved reserves for the field were 52% oil at June 30, 2015.
South Timbalier 21. We operate and have a 100% working interest in the South Timbalier 21 area, located six to ten miles offshore of Lafourche Parish, Louisiana in approximately 55 feet of water on OCS blocks South Timbalier 21, 22, 23, 26, 27, 28 and 41, as well as on two state leases. Block 26 and 41 were acquired through the EPL Acquisition. The South Timbalier 21 area, discovered by Gulf Oil Company and Shell Oil Company in the late 1950s and 1960s, has produced in excess of 488 MMBOE since production began in 1957 with the exception of South Timbalier 41, discovered by EPL in 2004, which has produced in excess of 24 MMBOE. The field is bounded on the north by a major Miocene expansion fault. Miocene sands are trapped structurally and stratigraphically from 7,000 feet to 15,000 feet in depth. A large counter-regional fault, along with salt and smaller faults, creates traps and separates hydrocarbon accumulations into individual compartments. There are 22 major production platforms and 35 smaller structures located throughout the fields and 58 active wells. The area’s net production for the month of June 2015 of 2.7 MBOED accounted for approximately 5% of our net production. Net proved reserves for the field were 94% oil at June 30, 2015. This field is the tenth largest oil field on the GoM Shelf.
Ultra Deep. With our partner Freeport McMoRan Oil & Gas, LLC, we have participated in eight projects to date, both offshore and onshore, with our participation interests ranging from approximately 9% to 23%. The operator announced on December 24, 2014, that the Highlander well completed a successful production test, which was performed in the Cretaceous/Tuscaloosa section. The operator and its partners commenced production in late February 2015. A second well location has been identified and future plans will be determined pending review of performance of the first well. The operator has identified multiple prospects in the Highlander area which provide opportunities for future development of the field and controls rights to more than 50,000 gross acres. The field’s net production for the month of June 2015 of 0.5 MBOED accounted for approximately 1% of our net production. Net proved reserves for the field were 100% gas at June 30, 2015.
Reserve Estimation Procedures and Internal Controls over Reserve Estimates
For fiscal year 2015, proved reserves were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc., independent oil and gas consultants (“NSAI”), as described in further detail under “Third Party Reserves Audit” below.
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Our internal controls policies over recording of reserves estimates require reserves to be in compliance with the definitions and regulations for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (“SEC”) staff interpretations and guidance and conform to the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas. Our internal controls over reserves estimates include, but are not limited to the following:
• | NSAI is engaged by the Board of Director Audit Committee (“Audit Committee”) to perform an audit of our processes and the reasonableness of our estimates of proved reserves and has direct access to the Audit Committee; |
• | Prior to issuance of the final reserves report, the Board of Directors meets with a representative of NSAI to review material variances, if any, between NSAI’s estimates and our estimates and to discuss any issues with the reserves evaluation process; |
• | Lease operating statements of the previous twelve months are analyzed to determine actual historical expenses and realized prices to be used in the economic analysis. Data entered into the reserves database is checked against data determined by the lease operating statement analysis; |
• | Updated capital costs are supplied by our Operations and Drilling Departments and entered by our reservoir engineers; |
• | Internal reserves estimates are prepared by the area asset reservoir engineers and reviewed by asset team management; |
• | Ownership interests, working interests and net revenue interests used in the net reserves calculation are compared against the Well Master to ensure accuracy; |
• | Proved undeveloped property drilling (and/or development) schedules are reviewed and approved by the Audit Committee and certain members of senior management; |
• | Senior management regularly reviews our drilling schedule and, after consultation and updates from the respective departments of the Company, approves any changes made to the existing long range plan and the related development plan. In addition, a comparison of actual proved undeveloped properties drilled (or developed) versus the associated previous fiscal year-end reserve report schedule is reviewed by the Board on a quarterly basis. This information is considered prior to approval of the current fiscal-year development schedule and associated reserves estimates. |
• | Material reserve variances are reviewed and approved by the Director of Reserves, or his designates, to ensure compliance and accuracy; |
• | All relevant data is compiled in a computer database application, to which only authorized personnel are given access rights consistent with their assigned job function; |
• | All reserves estimates have appropriate back-up documentation; |
• | Reserve estimates are finally reviewed and approved by our Director of Reserves and certain members of senior management; |
• | The Audit Committee reviews significant changes in our reserve estimates on an annual basis. |
Qualifications of Primary Internal Engineer and Third Party Engineers
Our Director of Reserves, Lee I. Williams, is the technical person primarily responsible for overseeing the preparation of our internal reserves estimates and for coordinating reserves audits conducted by NSAI. He has 15 years of industry experience with positions of increasing responsibility and has over 10 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1998 with a Bachelor of Science Degree in Petroleum Engineering.
The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional
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Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Connor B. Riseden and Mr. Shane M. Howell. Mr. Riseden has been practicing consulting petroleum engineering at NSAI since 2006. Mr. Riseden is a Licensed Professional Engineer in the State of Texas (No. 100566) and has over 13 years of practical experience in petroleum engineering, with over 13 years’ experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. Mr. Howell has been practicing consulting petroleum geology at NSAI since 2005. Mr. Howell is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 11276) and has over 17 years of practical experience in petroleum geosciences, with over 10 years’ experience in the estimation and evaluation of reserves. He graduated from San Diego State University in 1997 with a Bachelor of Science Degree in Geological Sciences and in 1998 with a Master of Science Degree in Geological Sciences. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The technical work was conducted by a team of nine NSAI petroleum engineers and geoscientists having an average industry experience of 17 years.
Technologies Used in Reserve Estimation
The SEC allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” is defined by the SEC as “much more likely to be produced than not” and “much more likely to increase or remain constant than to decrease.” Our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, pressure data and reservoir simulation.
Third-Party Reserves Audit
The estimate of reserves disclosed in this Form 10-K for fiscal 2015 is prepared by our reservoir engineers, and we are responsible for the adequacy and accuracy of those estimates. We engaged NSAI to perform an audit of our processes and the reasonableness of our estimates of proved reserves. NSAI audited 100% of our proved reserves.
NSAI prepared its own estimates of our proved reserves by using the data and documentation with which we used to prepare our own estimates. They then compare their estimates to ours for reasonableness. NSAI also examined our reserves categorization and future producing rates, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.
In conducting the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves as of June 30, 2015, based upon their evaluation concluding that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s letter is attached as Exhibit 99.1 to this Form 10-K.
9
Summary of Oil and Gas Reserves at June 30, 2015
The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the U.S. are based on evaluations prepared by our internal reservoir engineers and were audited by NSAI. Reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Summary of Oil and Gas Reserves as of June 30, 2015 Based on Average Fiscal-Year Prices | ||||||||||||||||||||||||
Oil MMBbls | NGLs MMBbls | Natural Gas Bcf | MMBOE | Percent of Total Proved | PV-10 (in thousands)(1) | |||||||||||||||||||
Proved | ||||||||||||||||||||||||
Developed | 88.6 | 5.4 | 188.0 | 125.3 | 68 | % | $ | 1,950,353 | ||||||||||||||||
Undeveloped | 41.0 | 2.1 | 90.5 | 58.2 | 32 | % | 884,083 | |||||||||||||||||
Total proved | 129.6 | 7.5 | 278.5 | 183.5 | 2,834,436 | |||||||||||||||||||
Future income taxes | 168,655 | |||||||||||||||||||||||
Less present value discount at 10% | 91,629 | |||||||||||||||||||||||
Future income taxes discounted at 10% | 77,026 | |||||||||||||||||||||||
Standardized measure of future discounted net cash flows | $ | 2,757,410 |
(1) | We refer to “PV-10” as the present value of estimated future net revenues of estimated proved reserves using a discount rate of 10%. This amount includes projected revenues less estimated production costs, abandonment costs and development costs. PV-10 is not a financial measure prescribed under accounting principles generally accepted in the U.S. (“U.S. GAAP”); therefore, the table reconciles this amount to the standardized measure of discounted future net cash flows, which is the most directly comparable U.S. GAAP financial measure. Management believes that the non-U.S. GAAP financial measure of PV-10 is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties. PV-10 is used internally when assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. We believe the use of this pre-tax measure is valuable because there are unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 is not a measure of financial or operating performance under U.S. GAAP, nor is it intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP. Average prices (calculated using the average of the first-day-of-the-month commodity prices during the 12-month period ending on June 30, 2015) used in determining future net revenues were $68.17 per barrel of oil for West Texas Intermediate benchmark plus $5.62 per barrel for crude quality and location differentials, for a total of $73.79 per barrel. For NGL’s, the average price used was $29.54 per barrel. For natural gas, the average price used was $3.08 per MMBtu. |
Changes in Proved Reserves
Our proved developed reserve estimates decreased by 24.6 MMBOE or 16% to 125.3 MMBOE at June 30, 2015 from 149.9 MMBOE at June 30, 2014. The decrease was primarily due to:
• | Downward revision of 12.8 MMBOE, primarily due to the effect of reduced oil and gas prices, |
• | Divestiture of 11.7 MMBOE, and |
• | Production of 21.5 MMBOE. |
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Offset by:
• | Additions of 8.5 MMBOE, primarily from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from six fields: South Pass 78, Lomond North, West Delta 73, Main Pass 61, South Timbalier 54 and South Pass 49, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Our proved undeveloped reserve estimates decreased by 38.1 MMBOE or 40% to 58.2 MMBOE at June 30, 2015 from 96.3 MMBOE at June 30, 2014. The decrease was primarily due to:
• | Downward revisions of 33.6 MMBOE comprised of (i) 7.3 MMBOE due to the effect of reduced oil and gas prices, (ii) 7.0 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 19.3 MMBOE due to new data and field studies. Of the 19.3 MMBOE of downward revisions due to new data and field studies, more than 80% occurred in the following seven fields: Grand Isle 16, Ship Shoal 208, South Timbalier 21, South Timbalier 26, Vermilion 164, West Delta 30 and West Delta 73, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Offset by:
• | Additions of 8.8 MMBOE, primarily from additional drilling locations to make up for the lower throughput per well in West Delta 73, a replacement location at Bayou Carlin, and from the identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 73. |
Development of Proved Undeveloped Reserves
Our proved undeveloped (“PUD”) reserves at June 30, 2015 were 58.2 MMBOE. Future development costs associated with our PUD reserves at June 30, 2015 totaled approximately $823 million. In the fiscal year ended June 30, 2015, we developed approximately 13.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 21 gross, 21 net wells at a net cost of approximately $237 million.
We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value, cash flow and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our PUD locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report, with the exception of four locations totaling 3,560 MBOE or 6.1% of our PUD reserves. These four locations are to be sidetracked from existing wellbores which are still producing economically and thus cannot be drilled until the proved developed producing zones deplete.
Although the schedule for development of our PUDs has historically changed based on external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in a given area, and our current PUD schedule is also subject to change due to external factors, we believe our PUDs will be converted in a timely manner given our enhanced focus on development drilling in our long range plan and current availability of capital to execute that plan. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan. The following table presents the percentage of PUD reserves scheduled to be developed by fiscal year, in accordance with our long range plan.
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Year Ending June 30, | Percentage of PUD Reserves Scheduled to be Developed | |||
2016 | 2.0 | % | ||
2017 | 17.4 | % | ||
2018 | 40.0 | % | ||
2019 | 24.2 | % | ||
2020 | 11.3 | % | ||
2021 – 2029 | 5.1 | % | ||
Total | 100.0 | % |
The following table discloses our progress toward the development of PUD reserves during the fiscal year ended June 30, 2015.
Oil and Natural Gas | Future Development Costs | |||||||
(MBOE) | (in thousands) | |||||||
Proved undeveloped reserves at June 30, 2014 | 96,256 | $ | 1,430,491 | |||||
Extensions and discoveries | 8,798 | 171,060 | ||||||
Revisions of previous estimates | (30,218 | ) | (288,697 | ) | ||||
Changes in prices and costs | (3,338 | ) | (240,002 | ) | ||||
Sales of reserves | (402 | ) | (12,400 | ) | ||||
Conversions to proved developed reserves | (12,945 | ) | (237,173 | ) | ||||
Total reduction in proved undeveloped reserves | (38,105 | ) | (607,212 | ) | ||||
Proved undeveloped reserves at June 30, 2015 | 58,151 | $ | 823,279 |
Drilling Activity
The following table sets forth our drilling activity for each of the three years ended June 30, 2015, 2014 and 2013:
Year Ended June 30, | ||||||||||||||||||||||||
2015 | 2014 | 2013 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Productive wells drilled | ||||||||||||||||||||||||
Development | 21.0 | 21.0 | 12.0 | 12.0 | 23.0 | 19.7 | ||||||||||||||||||
Exploratory | 3.0 | 1.7 | — | — | 1.0 | 0.1 | ||||||||||||||||||
Total | 24.0 | 22.7 | 12.0 | 12.0 | 24.0 | 19.8 | ||||||||||||||||||
Nonproductive wells drilled | ||||||||||||||||||||||||
Development | 1.0 | 1.0 | — | — | 3.0 | 3.0 | ||||||||||||||||||
Exploratory | 1.0 | 0.6 | 1.0 | 1.0 | 3.0 | 2.2 | ||||||||||||||||||
Total | 2.0 | 1.6 | 1.0 | 1.0 | 6.0 | 5.2 |
Present Activities
As of June 30, 2015, 1 gross well, representing approximately 1 net well, was being drilled.
Delivery Commitments
We had no delivery commitments in the three years ended June 30, 2015.
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Productive Wells
Our working interests in productive wells at June 30, 2015, and 2014 were as follows:
June 30, | ||||||||||||||||
2015 | 2014 | |||||||||||||||
Gross | Net | Gross | Net | |||||||||||||
Natural gas | 86 | 65 | 176 | 137 | ||||||||||||
Crude oil | 481 | 438 | 808 | 713 | ||||||||||||
Total | 567 | 503 | 984 | 850 |
Acreage
Working interests in developed and undeveloped acreage at June 30, 2015 were as follows:
June 30, 2015 | ||||||||||||||||||||||||
Developed Acres | Undeveloped Acres | Total Acres | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Onshore | 13,232 | 4,655 | 206,204 | 88,869 | 219,436 | 93,524 | ||||||||||||||||||
Offshore | 515,654 | 383,544 | 457,603 | 265,129 | 973,257 | 648,673 | ||||||||||||||||||
Total | 528,886 | 388,199 | 663,807 | 353,998 | 1,192,693 | 742,197 |
The following table summarizes potential expiration of our onshore and offshore undeveloped acreage for the years ending June 30, 2016, 2017 and 2018.
Year Ended June 30, | ||||||||||||||||||||||||
2016 | 2017 | 2018 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Onshore | 54,852 | 30,878 | 12,264 | 7,517 | 2,092 | 680 | ||||||||||||||||||
Offshore | — | — | 11,063 | 11,063 | 236,275 | 80,451 | ||||||||||||||||||
Total | 54,852 | 30,878 | 23,327 | 18,580 | 238,367 | 81,131 |
Capital Expenditures, Including Acquisitions and Costs Incurred
The supplementary data presented reflects information for all of our oil and natural gas producing activities. Costs incurred for oil and natural gas property acquisition, exploration and development activities are as follows:
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
(in thousands) | ||||||||||||
Property acquisitions | ||||||||||||
Proved | $ | — | $ | 2,046,879 | $ | 108,825 | ||||||
Unevaluated | 2,304 | 924,882 | 52,339 | |||||||||
Exploration costs | 38,183 | 153,136 | 168,512 | |||||||||
Development cost | 608,605 | 632,262 | 633,868 |
Oil and Natural Gas Production and Prices
Our average daily production represents our net ownership and includes royalty interests and net profit interests owned by us. Our average daily production and average sales prices follow.
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Sales Volumes per Day | ||||||||||||
Natural gas (MMcf) | 102.7 | 89.7 | 88.6 | |||||||||
NGLs (MBbls) | 2.7 | 2.4 | 2.3 | |||||||||
Crude oil (MBbls) | 39.1 | 27.7 | 26.0 |
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Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Total (MBOE) | 58.9 | 45.0 | 43.1 | |||||||||
Percent of BOE from crude oil and NGLs | 71 | % | 67 | % | 66 | % | ||||||
Average Sales Price | ||||||||||||
Natural gas per Mcf | $ | 3.13 | $ | 4.15 | $ | 3.48 | ||||||
NGLs per Bbl | $ | 28.09 | $ | 40.78 | $ | 38.38 | ||||||
Crude oil per Bbl | $ | 71.82 | $ | 105.86 | $ | 109.12 | ||||||
Sales price per BOE | $ | 54.41 | $ | 75.44 | $ | 75.14 |
Oil and Natural Gas Production, Prices and Production Costs — Significant Fields
The following field contains 15% or more of our total proved reserves as of June 30, 2015. Our average daily production, average sales prices and production costs are as follows:
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
West Delta 73 | ||||||||||||
Sales Volumes per Day | ||||||||||||
Natural gas (MMcf) | 4.3 | 7.5 | 9.0 | |||||||||
NGLs (MBbls) | 0.1 | 0.1 | 0.1 | |||||||||
Crude oil (MBbls) | 4.9 | 4.1 | 3.5 | |||||||||
Total (MBOE) | 5.8 | 5.5 | 5.1 | |||||||||
Percent of BOE from crude oil and NGLs | 86 | % | 75 | % | 71 | % | ||||||
Average Sales Price | ||||||||||||
Natural gas per Mcf | $ | 3.46 | $ | 4.22 | $ | 3.46 | ||||||
NGLs per Bbl | $ | 25.18 | $ | 40.74 | $ | 33.50 | ||||||
Crude oil per Bbl | $ | 68.63 | $ | 105.06 | $ | 109.11 | ||||||
Production cost per BOE | $ | 19.91 | $ | 19.76 | $ | 18.54 |
Production Unit Costs
Our production unit costs follow. Production costs include lease operating expense and production taxes.
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Average Cost per BOE | ||||||||||||
Production costs | ||||||||||||
Lease operating expense | ||||||||||||
Insurance expense | $ | 1.86 | $ | 1.90 | $ | 2.08 | ||||||
Workover and maintenance | 3.05 | 4.04 | 4.15 | |||||||||
Direct lease operating expense | 16.64 | 16.31 | 15.23 | |||||||||
Total lease operating expense | 21.55 | 22.25 | 21.46 | |||||||||
Production taxes | 0.39 | 0.33 | 0.33 | |||||||||
Total production costs | $ | 21.94 | $ | 22.58 | $ | 21.79 | ||||||
Gathering and transportation | $ | 0.98 | $ | 1.43 | $ | 1.54 | ||||||
Depreciation, depletion and amortization rates | $ | 32.81 | $ | 25.19 | $ | 23.16 |
Derivative Activities
We are actively engaged in a hedging program designed to manage our commodity price risk and enhance cash flow certainty and predictability. For further information regarding our risk management activities, please read Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” in this Form 10-K.
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Marketing and Customers
We market substantially all of our oil and natural gas production from the properties we operate. We also market more than half of our oil and natural gas production from the fields we do not operate. The majority of our operated oil and gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.
Shell Trading Company (“Shell”) accounted for approximately 29%, 45%, and 35% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014 and 2013, respectively. ExxonMobil accounted for approximately 26%, 43%, and 37% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014 and 2013, respectively. Chevron USA (“Chevron”) accounted for approximately 24% of our total oil and natural gas revenues during the year ended June 30, 2015. J.P. Morgan Ventures Energy Corporation accounted for 12% of our total oil and natural gas revenues during the year ended June 30, 2013. Beginning July 1, 2015, Trafigura Trading, LLC (“Trafigura”) replaced ExxonMobil and is expected to account for approximately 20 – 25% of our total oil and gas revenue from July 1, 2015 through December 31, 2015. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers of oil and natural gas, would purchase all or substantially all of our production in the event that Shell or Chevron curtailed their purchases.
We transport a portion of our oil and natural gas through third-party gathering systems and pipelines. Transportation space on these gathering systems and pipelines is normally readily available. Our ability to market our oil and gas has at times been limited or delayed due to restricted or unavailable transportation space or weather damage, and cash flow from the affected properties has been and could continue to be adversely impacted.
Government Regulation
Our oil and gas exploration, production and related operations and activities are subject to extensive rules and regulations promulgated by federal, state and local governmental agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.
Regulations affecting production. The jurisdictions in which we operate generally require permits for drilling operations, drilling bonds and operating reports and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. There is generally no regulation of wellhead prices or other, similar direct economic regulation of production, but there can be no assurance that this will remain true in the future.
In the event we conduct operations on federal, state or Indian oil and natural gas leases, our operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.
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Regulations affecting sales. The sales prices of oil, natural gas liquids and natural gas are not presently regulated but rather are set by the market. We cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.
The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas producers in our areas of operation.
The price we receive from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Rates charged and terms of service for the interstate pipeline transportation of oil, natural gas liquids and other refined petroleum products also are regulated by FERC. FERC has established an indexing methodology for changing the interstate transportation rates for oil pipelines, which allows such pipelines to take an annual inflation-based rate increase. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Market manipulation and market transparency regulations. Under the Energy Policy Act of 2005 (“EPAct 2005”), FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation of natural gas by “any entity” in order to enforce the anti-market manipulation provisions in the EPAct 2005. The Commodity Futures Trading Commission (“CFTC”) also holds authority to regulate certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. Likewise, the Federal Trade Commission (“FTC”) holds authority to regulate wholesale petroleum markets pursuant to the Federal Trade Commission Act and the Energy Independence and Security Act of 2007. With regard to our physical purchases and sales of natural gas, natural gas liquids, and crude oil, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC, FTC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation or, for the CFTC, triple the monetary gain to the violator, order disgorgement of profits, and recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third party damage claims by, among others, sellers, royalty owners and taxing authorities.
FERC has issued certain market transparency rules pursuant to its EPAct 2005 authority, which may affect some or all of our operations. FERC issued a final rule in 2007, as amended by subsequent orders on rehearing (“Order 704”), which requires wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including natural gas producers, gatherers, processors, and marketers, to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices, as explained in the order. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. FERC’s civil penalty authority under EPAct 2005 applies to violations of Order 704.
Oil Pipeline Regulations. We own interests in oil pipelines regulated by FERC under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (“EPAct of 1992”), and the rules and regulations promulgated under those laws and, thus, have interstate tariffs on file with FERC setting forth our interstate
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transportation rates and charges and the rules and regulations applicable to our jurisdictional transportation service. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil, natural gas liquids and refined petroleum products pipelines, be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. Under the ICA, shippers may challenge new or existing rates or services. FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in an oil pipeline paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. FERC generally has not investigated oil pipeline rates on its own initiative.
Under the EPAct of 1992, oil pipeline rates in effect for the 365-day period ending on the date of enactment of the EPAct of 1992 are deemed to be just and reasonable under the ICA, if such rates were not subject to complaint, protest or investigation during that 365-day period. These rates are commonly referred to as “grandfathered rates.” FERC may change grandfathered rates upon complaint only after it is shown that (i) a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate; (ii) the complainant was contractually barred from challenging the rate prior to enactment of the EPAct of 1992 and filed the complaint within 30 days of the expiration of the contractual bar; or (iii) a provision of the tariff is unduly discriminatory or preferential. The EPAct of 1992 places no similar limits on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential.
The EPAct of 1992 further required FERC to establish a simplified and generally applicable ratemaking methodology for interstate oil pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows oil pipelines to change their rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, plus 2.65 percent. Rate increases made under the index are subject to protest, but the scope of the protest proceeding is limited to an inquiry into whether the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. The indexing methodology is applicable to any existing rate, including a grandfathered rate. Indexing includes the requirement that, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling. However, the pipeline is not required to reduce its rates below the level deemed just and reasonable under the EPAct of 1992.
While an oil pipeline, as a general rule, must use the indexing methodology to change its rates, FERC also retained cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling (or when seeking to avoid lowering rates to the reduced rate ceiling), provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement.
Outer Continental Shelf Regulations. Our operations on federal oil and gas leases in the Gulf of Mexico are subject to regulation by the Bureau of Safety and Environmental Enforcement (“BSEE”) and the Bureau of Ocean Energy Management (“BOEM”). These leases contain relatively standardized terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the Outer Continental Shelf Lands Act (“OCSLA”). These laws and regulations are subject to change, and many new requirements were imposed by the BSEE and BOEM subsequent to the April 2010 Deepwater Horizon incident. For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (the “EPA”), lessees must obtain a permit from the BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the OCS, calculation of royalty payments and the valuation of production for this purpose, and removal of facilities.
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To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of ATP Oil and Gas, the BOEM indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.
We currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements. Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, the BOEM is actively seeking to adjust its financial assurance requirements for all companies operating in federal waters. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. Please read “Risk Factors — We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”
Under certain circumstances, the BSEE may require our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations. We own certain crude oil pipelines located on the OCS. BSEE regulates terms of service on OCS pipelines to provide open and nondiscriminatory access.
Gathering regulations. Section 1(b) of the federal Natural Gas Act (“NGA”) exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. Although FERC has not made any formal determinations with respect to any of the natural gas gathering pipeline facilities that we own, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to establish a pipeline’s status
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as a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities, however, has been the subject of substantial litigation and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. The classification and regulation of our gathering lines may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. In addition, our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services, though we do not believe that we would be affected by any such action in a manner differently than other companies in our areas of operation.
Environmental Regulations
Various federal, state and local laws and regulations relating to the protection of the environment, including the discharge of materials into the environment, may affect our exploration, development and production operations and the costs of those operations. These laws and regulations, among other things, govern the amounts and types of substances that may be released into the environment, the issuance of permits to conduct exploration, drilling and production operations, the handling, discharge and disposition of waste materials, the reclamation and abandonment of wells, sites and facilities, the establishment of financial assurance requirements for oil spill response costs and the decommissioning of offshore facilities and the remediation of contaminated sites. These laws and regulations may impose liabilities for noncompliance and contamination resulting from our operations and may require suspension or cessation of operations in affected areas.
The environmental laws and regulations applicable to us and our operations include, among others, the following United States federal laws and regulations:
• | Clean Air Act, and its amendments, which governs air emissions; |
• | Clean Water Act, which governs discharges of pollutants into waters of the United States; |
• | Comprehensive Environmental Response, Compensation and Liability Act, which imposes strict liability where releases of hazardous substances have occurred or are threatened to occur (commonly known as “Superfund”); |
• | Resource Conservation and Recovery Act, which governs the management of solid waste; |
• | Endangered Species Act, Marine Mammal Protection Act, and Migratory Bird Treaty Act, which govern the protection of animals, flora and fauna; |
• | Oil Pollution Act of 1990, which imposes liabilities resulting from discharges of oil into navigable waters of the United States; |
• | Emergency Planning and Community Right-to-Know Act, which requires reporting of toxic chemical inventories; and |
• | Safe Drinking Water Act, which governs underground injection and disposal activities; and |
• | U.S. Department of Interior regulations, which impose liability for pollution cleanup and damages. |
We believe our operations are in compliance with applicable environmental laws and regulations. We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully
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insured against all such risks. Our insurance coverage provides for the reimbursement to us of costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses and since regulatory requirements frequently change and may become more stringent, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.
Oil Pollution Act. The Oil Pollution Act of 1990 (“OPA”) and regulations adopted pursuant to OPA impose a variety of requirements on “responsible parties” related to the prevention of and response to oil spills into waters of the United States, including the OCS. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns joint and several, strict liability, without regard to fault, to each responsible party, for all containment and cleanup costs and a variety of public and private damages arising from a spill, including, but not limited to, the costs of responding to a release of oil to surface waters, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. In addition, in December 2014, the BOEM issued a final rule, effective January 12, 2015, which raises OPA’s damages liability cap from $75 million to $133.65 million. OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the OCS, although the Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if there were to occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.
Climate Change. The U.S. Environmental Protection Agency (the “EPA”) has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and another requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore and offshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40 to 45% from 2012 emission levels by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. As the number of emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.
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The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
Employees
We had 378 employees at June 30, 2015, none of which were represented by labor unions or covered by any collective bargaining agreement. We consider relations with our employees to be satisfactory and we have never experienced a work stoppage or strike. We regularly use independent consultants and contractors to perform various professional services in various areas, including in our exploration and development operations, production operations and certain administrative functions.
Available Information
We file or furnish annual, quarterly and current reports and other documents with the SEC under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”). The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents we file with the SEC atwww.sec.gov.
Our web site address iswww.energyxxi.com. We make available, free of charge on or through our web site, our Annual Report on Form 10-K, proxy statement, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or accessible through, our website is not incorporated by reference into this Form 10-K.
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Item 1A. Risk Factors
Oil and natural gas prices are volatile, and a substantial or extended decline in oil and natural gas prices would adversely affect our financial results and impede our growth.
Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future. For example, oil prices declined severely during the our 2015 fiscal year with continued lower prices in the first quarter of our fiscal year 2016. The WTI crude oil price per barrel for the period from July 1, 2014 to June 30, 2015 ranged from a high of $105.34 to a low of $43.46, a decrease of 58.7%, and the NYMEX natural gas price per MMBtu for the period July 1, 2014 to June 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 22, 2015, the spot market price for WTI was $45.83. Prices for oil and natural gas fluctuate widely in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:
• | domestic and foreign supplies of oil and natural gas; |
• | price and quantity of foreign imports of oil and natural gas; |
• | actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls; |
• | level of consumer product demand, including as a result of competition from alternative energy sources; |
• | level of global oil and natural gas exploration and production activity; |
• | domestic and foreign governmental regulations; |
• | level of global oil and natural gas inventories; |
• | political conditions in or affecting other oil-producing and natural gas-producing countries, including the current conflicts in the Middle East and conditions in South America and Russia; |
• | weather conditions; |
• | technological advances affecting oil and natural gas production and consumption; |
• | overall U.S. and global economic conditions; and |
• | price and availability of alternative fuels. |
Our financial condition, revenues, profitability and the carrying value of our properties depend upon the prevailing prices and demand for oil and natural gas. The speed and severity of the decline in oil prices during our 2015 fiscal year and the continued lower prices in the first quarter of our fiscal year 2016 has materially affected our results of operations and our estimates of our proved oil and natural gas reserves. Any sustained periods of low prices for oil and natural gas are likely to materially and adversely affect our financial position, the quantities of natural gas and oil reserves that we can economically produce, our cash flow available for capital expenditures and our ability to access funds under our revolving credit facility and through the capital markets.
We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.
As of June 30, 2015, we had total indebtedness of $4,608 million and, as of September 22, 2015, we had total indebtedness of $4,185 million as a result of certain debt repurchases by the Company subsequent to June 30, 2015. Based on our current debt balance, we expect to have substantial interest payments due during fiscal year 2016, totaling $367.0 million. In addition, the majority of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. The maturity dates for our outstanding notes are as follows (debt amounts as of September 22, 2015, reflecting note repurchases completed by the company subsequent to June 30, 2015):
• | 9.25% Senior Notes due December 15, 2017 ($750 million) (the “9.25% Senior Notes”) |
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• | 8.25% Senior Notes due February 15, 2018 ($510 million) (the “8.25% Senior Notes”) |
• | 3.0% Convertible Notes due December 15, 2018 ($400 million) (the “3.0% Convertible Notes”) |
• | 7.75% Senior Notes due June 15, 2019 ($126.3 million) (the “7.75% Senior Notes”) |
• | 11.0% Senior Secured Second Lien Notes due March 15, 2020 ($1.45 billion) (the “11.0% Notes”) |
• | 7.5% Senior Notes due December 15, 2021 ($246.3 million) (the “7.5% Senior Notes”) |
• | 6.875% Senior Notes due March 15, 2024 ($599.6 million) (the “6.875% Senior Notes”) |
In addition, the maturity of certain of our outstanding indebtedness may be accelerated in certain situations. Pursuant to the indenture governing our 11.0% Notes, we will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes (December 15, 2017), if on such date the aggregate outstanding principal amount of all such notes exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes (February 15, 2018), if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million. In addition, our revolving credit facility is scheduled to mature on April 9, 2018; however, the maturity of our revolving credit facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017.
Our ability to make scheduled payments on, or to refinance, our debt obligations will depend on our financial and operating performance, which is subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We cannot assure you that our business will generate sufficient cash flows from operating activities or that future sources of capital will be available to us in an amount sufficient to permit us to service our indebtedness or repay our indebtedness as it becomes due or to fund our other liquidity needs. In addition, there can be no assurance that we will have the ability to borrow or otherwise raise the amounts necessary to repay or refinance our indebtedness as it matures. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we may be required to:
• | Restructure or refinance all or a portion of our debt; |
• | obtain additional financing; |
• | sell some of our assets or operations; or |
• | reduce or delay capital expenditures, including development and exploration efforts and acquisitions. |
We may be unable to restructure or refinance our debt, obtain additional financing or capital or sell assets on satisfactory terms, if at all. If we cannot make scheduled payments on our debt, we will be in default under the terms of the agreements governing our debt and, as a result:
• | our debt holders could declare all outstanding principal and interest to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements and the holders of our 11.0% Notes due March 15, 2020 could foreclose against the assets securing their notes; |
• | the lenders under our revolving credit facility could terminate their commitments to lend us money and foreclose against the assets securing their borrowings; and |
• | we could be forced into bankruptcy or liquidation. |
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Our significant level of indebtedness may limit our ability to borrow additional funds or capitalize on acquisition or other business opportunities. In addition, the covenants in the indentures governing our senior notes and our revolving credit facility impose restrictions that may limit our ability and the ability of our subsidiaries to take certain actions. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.
As of June 30, 2015, we had total indebtedness of $4,608 million. Our leverage and the current and future restrictions contained in the agreements governing our indebtedness may reduce our ability to incur additional indebtedness, engage in certain transactions or capitalize on acquisition or other business opportunities. Our indebtedness and other financial obligations and restrictions could have financial consequences. For example, they could:
• | impair our ability to obtain additional financing in the future for capital expenditures, potential acquisitions, general business activities or other purposes; |
• | increase our vulnerability to general adverse economic and industry conditions; |
• | result in higher interest expense in the event of increases in interest rates since some of our debt is at variable rates of interest; |
• | require us to dedicate a substantial portion of future cash flow to payments of our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate requirements; |
• | limit our flexibility in planning for, or reacting to, changes in our business and industry; and |
• | place us at a competitive disadvantage to those who have proportionately less debt. |
In addition, our revolving credit facility contains and our indentures governing our secured notes and unsecured notes contain covenants that restrict EGC and its subsidiaries’ ability to take various actions, such as:
• | engaging in businesses other than the oil and gas business; |
• | incurring or guaranteeing additional indebtedness or issuing disqualified capital stock; |
• | making investments; |
• | paying dividends, redeeming certain indebtedness or making other restricted payments; |
• | entering into transactions with affiliates; |
• | creating or incurring liens; |
• | transferring or selling assets; |
• | incurring dividend or other payment restrictions affecting certain subsidiaries; |
• | consummating a merger, consolidation or sale of all or substantially all our assets; and |
• | entering into sale/leaseback transactions. |
In addition, under our revolving credit facility, there is a restriction on changes in our management. If John D. Schiller, Jr. ceases to be our chief executive officer (except as a result of his death or disability) and a reasonably acceptable successor is not appointed within 180 days, the lenders of our revolving credit facility could declare amounts outstanding thereunder immediately due and payable. In the event that Mr. Schiller ceases to be our chief executive officer, amounts outstanding under our revolving credit facility would not automatically be reclassified as current debt as it is probable that we could identify a successor within the 180 day period. Our revolving credit facility requires, and any future credit facilities may require, us to comply with specified financial ratios, including regarding interest coverage and total leverage coverage.
Our ability to comply with these covenants will likely be affected by events beyond our control and we cannot assure you that we will satisfy those requirements. A prolonged period of oil and gas prices at current levels or a further decline could further increase the risk of our inability to comply with covenants to maintain
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specified financial ratios. A breach of any of these provisions could result in a default under our debt instruments, which could allow all amounts outstanding thereunder to be declared immediately due and payable, which would in turn trigger cross-acceleration and cross-default rights under our other debt. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings or they could prevent us from making payments on the notes in the event of acceleration of our outstanding indebtedness. In the event of such acceleration, we cannot assure that we would be able to repay our debt or obtain new financing to refinance our debt. Even if new financing was made available to us, it may not be on terms acceptable to us. We may also be prevented from taking advantage of business opportunities that arise if we fail to meet certain ratios or because of the limitations imposed on us by the restrictive covenants under these instruments.
We may be able to incur additional debt in the future. This could exacerbate the risks associated with our indebtedness.
Despite our current level of indebtedness, we may incur more debt in the future, which could further exacerbate the risks described above. The terms of the indentures governing our 11.0% Notes and our revolving credit facility would allow us to incur more secured and unsecured indebtedness, which in each case could intensify the related risks that we now face.
The indenture governing the 8.25% Senior Notes due 2018 includes restrictive covenants which adversely affect the business and operations of the combined company.
The covenants included in the indenture governing EPL’s 8.25% Senior Notes that EGC assumed in the EPL Acquisition include certain restrictive covenants that provide less operational flexibility than the covenants governing our other outstanding indebtedness. Specifically, the indenture governing the 8.25% Senior Notes, among other things, (i) will not allow pledging of EPL’s assets to secure the non-EPL tranche borrowings under our revolving credit facility, our second lien notes or any other secured indebtedness of EGC, (ii) will not permit EPL and its subsidiaries to be added as a guarantor of any notes issued by EGC or indebtedness of EGC under our revolving credit facility and (iii) restricts our ability to distribute cash from EPL to EGC or its other subsidiaries. Unless and until we are able to amend, replace or refinance the 8.25% Senior Notes, the restrictive covenants of such notes have made it more difficult to integrate our operations with EPL, rationalize our capital structure and operate the combined company in the most efficient manner. Our failure in this regard could adversely affect our future business and operations. In addition, certain defaults or an acceleration under the 8.25% Senior Notes could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness.
Continued Low Commodity Prices May Impact Our Ability to Comply With Debt Covenants
Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement at least through June 30, 2016; however, commodity prices have been extremely volatile in recent history and a protracted further decline in commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods. A breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. Certain payment defaults or acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.
We expect to have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms.
We expect to make substantial capital expenditures related to our oil and gas properties. Our capital requirements depend on numerous factors making it difficult to predict the timing and amount of such capital expenditures. We intend to primarily finance our near term capital expenditures with cash on hand. However,
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if our capital requirements vary materially from those provided for in our current projections, we may require additional financing. A decrease in expected revenues or an adverse change in market conditions could make obtaining this financing economically unattractive or impossible.
The cost of raising money in the debt and equity capital markets may increase substantially while the availability of funds from those markets may diminish significantly. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets may increase as lenders and institutional investors could increase interest rates, impose tighter lending standards, refuse to refinance existing debt at maturity at all or on terms similar to our current debt and, in some cases, cease to provide funding to borrowers.
An increase in our indebtedness, as well as the credit market and debt and equity capital market conditions discussed above could negatively impact our ability to remain in compliance with the financial covenants under our revolving credit facility which could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth as expected, we could be required to seek alternative financing, the terms of which may be less favorable to us, or not pursue growth opportunities.
Without additional capital resources, we may be forced to limit or defer our planned natural gas and oil exploration and development program and this will adversely affect the recoverability and ultimate value of our natural gas and oil properties, in turn negatively affecting our business, financial condition and results of operations. We may also be unable to obtain sufficient credit capacity with counterparties to finance the hedging of our future crude oil and natural gas production which may limit our ability to manage price risk. As a result, we may lack the capital necessary to complete potential acquisitions, obtain credit necessary to enter into derivative contracts to hedge our future crude oil and natural gas production or to capitalize on other business opportunities.
We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.
To cover the various obligations of lessees on the OCS, such as the cost to plug and abandon wells and decommission and remove platforms and pipelines at the end of production, the BOEM generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met, unless the BOEM exempts the lessee from such financial assurance requirements. As a result of the bankruptcy of another Gulf of Mexico operator, the BOEM indicated that it may review the estimated cost of future plugging, abandonment, decommissioning and removal obligations of other OCS operators, may evaluate any waivers or exemptions for such financial assurance obligations, and may increase the amount of financial assurance required with respect to these obligations. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.
We currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. However, with respect to our existing bonds and letters of credit with third parties, we can provide no assurance that the BOEM will consider them when determining
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the total value of additional financial assurances and/or bonding we must provide. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for certain other properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements.
Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, the BOEM is actively seeking to adjust its financial assurance requirements for all companies operating in federal waters. In August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide letters of credit to support the issuance of these bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
Our estimates of future asset retirement obligations may vary significantly from period to period and are especially significant because our operations include the U.S. Gulf of Mexico.
We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas production operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations are many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased costs. As a result, we may make significant increases or decreases to our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane.
Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the U.S. Gulf of Mexico following the DOI’s issuance of a Notice to Lessees (“NTL”), effective October 2010, that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the U.S. Gulf of Mexico. Historically, many oil and natural gas producers in the Gulf of Mexico have delayed the plugging, abandoning or removal of idle iron until they met the final decommissioning regulatory requirement, which has been established as being within one year after the lease expires or terminates, a time period that sometimes is years after use of the idle iron has been discontinued. The idle iron NTL establishes new triggers for commencing decommissioning activities — any well that has
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not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years’ time. Plugging or abandonment of wells may be delayed by two years if all of such wells’ hydrocarbon and sulfur zones are appropriately isolated. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. Moreover, as a result of the implementation of this NTL, there is expected to be increased demand for salvage contractors and equipment operating in the U.S. Gulf of Mexico, resulting in increased estimates of plugging, abandonment and removal costs and associated increases in operators’ asset retirement obligations.
In addition, in August 2014, the BOEM issued an Advanced Notice of Proposed Rulemaking in which the agency indicated that it was considering increasing the financial assurance requirements, and it currently plans to publish a draft rule in late 2015. The BOEM is also considering revising its supplemental bonding procedures by shifting from the current “waiver” model for self-insurance to a credit-based model, and the BOEM is planning to implement these supplemental bonding changes in a Revised Notice to Lessees in late 2015. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Please read “We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”
Lower oil and gas prices and other factors may result in ceiling test write-downs of our asset carrying values.
Under the full cost method of accounting, we are required to perform each quarter a “ceiling test” that determines a limit on the book value of our oil and natural gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unevaluated oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10%, net of related tax effects, plus the cost of unevaluated oil and natural gas properties, the excess is charged to expense and reflected as additional accumulated depreciation, depletion and amortization. As of the reported balance sheet date, capitalized costs of an oil and gas producing company may not exceed the full cost limitation calculated under the above described rule based on the average prices for oil and natural gas. However, if prior to the balance sheet date, we enter into certain hedging arrangements for a portion of our future oil and natural gas production, thereby enabling us to receive future cash flows that are higher than the estimated future cash flows indicated, these higher hedged prices are used if they qualify as cash flow hedges.
The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. For the third and fourth quarters of fiscal year 2015, we recognized ceiling test write-downs of our oil and natural gas properties totaling $2,421.9 million.
Based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month for the 12 months ending September 30, 2015, we presently expect to incur a further impairment of $900 million to $1,200 million in the first fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues beyond first fiscal quarter of 2016, we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.
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The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves.
This Form 10-K contains estimates of our future net cash flows from our proved reserves. We base the estimated discounted future net cash flows from our proved reserves on average prices for the preceding twelve-month period and costs in effect at the time of the estimate. As a result of significant recent declines in commodity prices, such average sales prices are significantly in excess of more recent prices. Unless commodity prices or reserves increase, the estimated discounted future net cash flows from our proved reserves would generally be expected to decrease as additional months with lower commodity sales prices will be included in this calculation in the future. Actual future net cash flows from our natural gas and oil properties will be affected by factors such as:
• | the volume, pricing and duration of our natural gas and oil hedging contracts; |
• | supply of and demand for natural gas and oil; |
• | actual prices we receive for natural gas and oil; |
• | our actual operating costs in producing natural gas and oil; |
• | the amount and timing of our capital expenditures and decommissioning costs; |
• | the amount and timing of actual production; and |
• | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Our actual recovery of reserves may differ from our proved reserve estimates.
This Form 10-K contains estimates of our proved oil and gas reserves. Estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing such estimates, projection of production rates, timing of development expenditures and available geological, geophysical, production and engineering data are analyzed. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. If our interpretations or assumptions used in arriving at our reserve estimates prove to be inaccurate, the amount of oil and gas that will ultimately be recovered may differ materially from the estimated quantities and net present value of reserves owned by us. Any inaccuracies in these interpretations or assumptions could also materially affect the estimated quantities of reserves shown in the reserve reports summarized in this Form 10-K. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, decommissioning liabilities and quantities of recoverable oil and gas reserves most likely will vary from estimates. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.
We have included in this Form 10-K certain estimates of our proved reserves as of June 30, 2015 prepared in a manner consistent with our interpretation of the SEC rules relating to reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent
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petroleum consultant performing an audit of our reserve estimates. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Further, if we postpone drilling of proved undeveloped reserves beyond this five-year development horizon, whether in response to a continued depressed commodity price environment or otherwise, we may have to write off reserves previously recognized as proved undeveloped. However, we cannot assure you that our long-term plans will not change based on commodity prices, costs or our liquidity in a manner that would require us to reduce our proved reserve estimate in the future due to the five-year development rule or otherwise.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
Approximately 32% of our proved reserves as of June 30, 2015 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserves data included in the reserves engineer reports assumes that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. In addition, there are external factors such as changes in commodity prices, the availability of capital, the availability of drilling rigs (capable of drilling in the given area), that could result in certain development plans being delayed and/or accelerated relative to the current schedule.
Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. For example, our proved reserves of 183.5 MMBOE and $2.8 billion of PV-10 as of June 30, 2015 were lower than our proved reserves of 246.2 MMBOE and $7.6 billion of PV-10 as of June 30, 2014 in part due to the rescheduling or write off of certain of our reserves as a result of lower oil and gas prices and reductions in our capital expenditure budget as compared to our June 30, 2014 reserve report. Delays in the development of these reserves could cause us to have to reclassify our proved reserves as unproved reserves. Please read “Business — Development of Proved Undeveloped Reserves.”
As of June 30, 2015, approximately 32% of our total proved reserves were undeveloped and approximately 16% of our total proved reserves were developed non-producing. There can be no assurance that all of those reserves will ultimately be developed or produced.
While we have plans or are in the process of developing plans for exploiting and producing a majority of our proved reserves, there can be no assurance that all of those reserves will ultimately be developed or produced. Furthermore, there can be no assurance that all of our undeveloped and developed non-producing reserves will ultimately be produced during the time periods we have planned, at the costs we have budgeted, or at all, which could result in the write-off of previously recognized reserves.
Unless we replace crude oil and natural gas reserves, our future reserves and production will decline.
A large portion of our drilling activity is located in mature oil-producing areas of the GoM Shelf. Accordingly, increases in our future crude oil and natural gas production depend on our success in developing, finding or acquiring additional reserves that are economically recoverable. If we are unable to replace reserves through drilling or acquisitions on economic terms, our level of production and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of crude oil and natural gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. We also may not be successful in raising funds to acquire additional reserves.
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Production periods or reserve lives for Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.
High production rates generally result in recovery of a relatively higher percentage of reserves from properties in the Gulf of Mexico during the initial few years when compared to other regions in the U.S. Typically, 50% of the reserves of properties in the Gulf of Mexico are depleted within three to four years with natural gas wells having a higher rate of depletion than oil wells. Due to high initial production rates, production of reserves from reservoirs in the Gulf of Mexico generally decline more rapidly than from other producing reservoirs. The vast majority of our existing operations are in the Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other oil and gas companies with longer-life reserves in other producing areas. Also, our expected revenues and return on capital will depend on prices prevailing during these relatively short production periods. Our need to generate revenues to fund ongoing capital commitments or repay debt may limit our ability to slow or shut in production from producing wells during periods of low prices for oil and natural gas.
The borrowing base under our revolving credit facility may be reduced in the future if commodity prices decline, which will limit our available funding for exploration and development. We may have difficulty obtaining additional credit, which could adversely affect our operations and financial position.
We depend on our revolving credit facility for a portion of our future capital needs. In March 2015, we reduced the borrowing base under our revolving credit facility from $1,500 million to $500 million. As of June 30, 2015, we had borrowed $150 million and had $226 million in letters of credit issued under our revolving credit facility, with $124 million of remaining available borrowing capacity.
In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (1) a decrease in our borrowing base due to the outcome of a subsequent borrowing base redetermination, or (2) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.
Our borrowing base will be redetermined semi-annually by our lenders in their sole discretion. We expect the next determination of the borrowing base under our revolving credit facility will occur in the fall of 2015, although an early redetermination is possible. In addition, the lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. The lenders will redetermine the borrowing base based on an engineering report with respect to our natural gas and oil reserves, which will take into account the prevailing natural gas and oil prices at such time. If oil and natural gas commodity prices continue to deteriorate, the revised borrowing base under our revolving credit facility may be reduced. If the borrowing base is reduced or maintained, the new borrowing base is subject to approval by banks holding not less than 67% of the lending commitments under our revolving credit facility, and the final borrowing base may be lower than the level recommended by the agent for the bank group. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other natural gas and oil properties as additional collateral. We do not currently have any substantial properties which could serve as additional collateral, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility.
As a result, we may be unable to obtain adequate funding under our revolving credit facility. If funding is not available when needed, or is available only on unfavorable terms, it could adversely affect our development plans as currently anticipated, which could have a material adverse effect on our production, revenues and results of operations.
Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, making us vulnerable to risks associated with operating in one geographic area.
Unlike other entities that are geographically diversified, we do not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. By consummating acquisitions only in the Gulf of Mexico and the U.S. Gulf Coast, our lack of diversification may:
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• | subject us to numerous economic, competitive and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate; and |
• | result in our dependency upon a single or limited number of hydrocarbon basins. |
In addition, the geographic concentration of our properties in the Gulf of Mexico and the U.S. Gulf Coast means that some or all of the properties could be affected should the region experience:
• | severe weather, such as hurricanes and other adverse weather conditions; |
• | delays or decreases in production, the availability of equipment, facilities or services; |
• | delays or decreases in the availability of capacity to transport, gather or process production; and/or |
• | changes in the regulatory environment. |
For example, the oil and gas properties that we acquired in February 2006 were damaged by both Hurricanes Katrina and Rita, and again by Hurricanes Gustav and Ike and the oil and gas properties that we acquired in June 2007 were damaged by Hurricanes Katrina and Rita. This damage required us to spend time and capital on inspections, repairs, debris removal, and the drilling of replacement wells. In accordance with industry practice, we maintain insurance against some, but not all, of these risks and losses. For additional information, please read “— Our insurance may not protect us against all of the operating risks to which our business is exposed.”
Because all or a number of the properties could experience many of the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.
The nature of our business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
We engage in exploration and development drilling activities in the GoM Shelf, which activities are inherently risky. These activities may be unsuccessful for many reasons. In addition to a failure to find oil or natural gas, drilling efforts can be affected by adverse weather conditions such as hurricanes and tropical storms in the Gulf of Mexico, cost overruns, equipment shortages and mechanical difficulties. Therefore, the successful drilling of an oil or gas well does not ensure we will realize a profit on our investment. A variety of factors, both geological and market-related, could cause a well to become uneconomic or only marginally economic. In addition to their costs, unsuccessful wells could impede our efforts to replace reserves.
Our business involves a variety of operating risks, which include, but are not limited to:
• | fires; |
• | explosions; |
• | blow-outs and surface cratering; |
• | uncontrollable flows of gas, oil and formation water; |
• | natural disasters, such as hurricanes and other adverse weather conditions; |
• | pipe, cement, subsea well or pipeline failures; |
• | casing collapses; |
• | mechanical difficulties, such as lost or stuck oil field drilling and service tools; |
• | abnormally pressured formations; and |
• | environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases. |
If we experience any of these problems, well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect our ability to conduct operations. We could also incur substantial losses due to costs and/or liability incurred as a result of:
• | injury or loss of life; |
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• | severe damage to and destruction of property, natural resources and equipment; |
• | pollution and other environmental damage; |
• | clean-up responsibilities; |
• | regulatory investigations and penalties; |
• | suspension of our operations; and |
• | repairs to resume operations. |
Our offshore operations involve special risks that could affect our operations adversely.
Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. In particular, we are not intending to put in place business interruption insurance due to its high cost. We therefore may not be able to rely on insurance coverage in the event of such natural phenomena.
Unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.
We may become responsible for unanticipated costs associated with abandoning and reclaiming wells, facilities and pipelines. Abandonment and reclamation of facilities and the costs associated therewith is often referred to as “decommissioning.” Should decommissioning be required that is not presently anticipated or the decommissioning be accelerated, such as can happen after a hurricane, such costs may exceed the value of reserves remaining at any particular time. We may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could have a material adverse effect on our financial position and results of operations.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Due to market conditions, including with respect to commodity prices such as for oil and natural gas, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance policies are economically unavailable or available only for reduced amounts of coverage. Consistent with industry practice, we are not fully insured against all risks, including high-cost business interruption insurance and drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations. Due to a number of catastrophic events like the terrorist attacks on September 11, 2001, Hurricanes Ivan, Katrina, Rita, Gustav and Ike, and the April 20, 2010 Deepwater Horizon incident, insurance underwriters increased insurance premiums for many of the coverages historically maintained and issued general notices of cancellation and significant changes for a wide variety of insurance coverages. The oil and natural gas industry suffered damage from Hurricanes Ivan, Katrina, Rita, Gustav and Ike. As a result, insurance costs have increased significantly from the costs that similarly situated participants in this industry have historically incurred. Insurers are requiring higher retention levels and limit the amount of insurance proceeds that are available after a major wind storm in the event that damages are incurred. If storm activity in the future is severe, insurance underwriters may no longer insure Gulf of Mexico assets against weather-related damage. In addition, we do not have, and it is unlikely we will obtain, business interruption insurance due to its high cost. If an accident or other event resulting in damage to our operations, including severe weather, terrorist acts, war, civil disturbances, pollution or environmental damage, occurs and is not fully covered by insurance or a recoverable indemnity from a vendor, it could adversely affect our financial condition and results of operations. Moreover, we may not be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks.
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Weather Based Insurance Linked Securities may not payout in case of a hurricane or may not fully cover damage.
We utilize Weather Based Insurance Linked Securities (“Securities”) to supplement our windstorm insurance coverage to mitigate potential loss to our most valuable oil and gas properties from hurricanes in the Gulf of Mexico. These Securities are generally structured to provide for payments of negotiated amounts should a hurricane having a pre-established category pass within specific pre-defined areas encompassing our oil and gas producing fields. While these Securities are meant to provide some excess windstorm coverage, there can be no certainty that these Securities will meet the payout criteria even if there is substantial damage by a hurricane of a lower category than that specified in the Securities. In addition, the payment made may not be sufficient to cover any actual damage incurred from a storm.
Competition for oil and gas properties and prospects is intense and some of our competitors have larger financial, technical and personnel resources that could give them an advantage in evaluating and obtaining properties and prospects.
We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and gas and securing trained personnel. Many of our competitors are major or independent oil and gas companies that possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than ours. We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from the BOEM are acquired through a “sealed bid” process and are generally awarded to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. The competitors may also have a greater ability to continue drilling activities during periods of low oil and gas prices, such as the current decline in oil prices, and to absorb the burden of current and future governmental regulations and taxation. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to pay more for productive oil and gas properties and exploratory prospects than we are able or willing to pay. Further, our competitors may be able to expend greater resources on the existing and changing technologies that we believe will impact attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.
Market conditions or transportation impediments may hinder access to oil and gas markets, delay production or increase our costs.
Market conditions (including with respect to commodity prices such as for oil and natural gas), the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay production. The availability of a ready market for oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, market access depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. Restrictions on our ability to sell our oil and natural gas may have several other adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possible loss of a lease due to lack of production. In the event that we encounter restrictions in our ability to tie our production to a gathering system, we may face considerable delays from the initial discovery of a reservoir to the actual production of the oil and gas and realization of revenues. In some cases, our wells may be tied back to platforms owned by parties with no economic interests in these wells. There can be no assurance that owners of such platforms will continue to operate the platforms. If the owners cease to operate the platforms or their processing equipment, we may be required to shut in the associated wells, which could adversely affect our results of operations.
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Most of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
We own leasehold interests in areas not currently held by production. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. We have leases on 54,852 gross acres (30,878 net) that could potentially expire during fiscal year 2016.
Our drilling plans for areas not currently held by production are subject to change based upon various factors. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On our acreage that we do not operate, we have less control over the timing of drilling, therefore there is additional risk of expirations occurring in those sections.
We are not the operator on all of our properties and therefore are not in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves on such properties.
As we carry out our planned drilling program, we will not serve as operator of all planned wells. We operated approximately 97% of our proved reserves at June 30, 2015. As a result, we may have limited ability to exercise influence over the operations of some non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:
• | the timing and amount of capital expenditures; |
• | the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel; |
• | the operator’s expertise and financial resources; |
• | approval of other participants in drilling wells; |
• | selection of technology; and |
• | the rate of production of the reserves. |
Each of these factors, including others, could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
We are exposed to trade credit risk in the ordinary course of our business activities.
We are exposed to risks of loss in the event of nonperformance by our vendors, customers and by counterparties to our price risk management arrangements. Some of our vendors, customers and counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors, customers and counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. From time to time, the availability of credit is more restrictive. Additionally, many of our vendors’, customers’ and counterparties’ equity values have substantially declined. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors, customers and counterparties liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors, customers and/or counterparties could reduce our cash flows.
We sell the majority of our production to three customers.
Shell, ExxonMobil and Chevron each accounted for approximately 29%, 26% and 24%, respectively, of our total oil and natural gas revenues during the year ended June 30, 2015. Beginning July 1, 2015, Trafigura replaced ExxonMobil and is expected to account for approximately 20 – 25% of our total oil and gas revenue
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from July 1, 2015 through December 31, 2015. Our inability to continue to sell our production to Shell, Chevron or Trafigura, if not offset by sales with new or other existing customers, could have a material adverse effect on our business and operations.
Our success depends on dedicated and skillful management and staff, whose departure could disrupt our business operations.
Our success depends on our ability to retain and attract experienced engineers, geoscientists and other professional staff. We depend to a large extent on the efforts, technical expertise and continued employment of these personnel and members of our management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, our business operations could be adversely affected.
Additionally, if John D. Schiller, Jr. ceases to be our chief executive officer (except as a result of his death or disability) and a reasonably acceptable successor is not appointed within 180 days, the lenders of our revolving credit facility could declare amounts outstanding thereunder immediately due and payable. Such an event could have a material adverse effect on our business and operations.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute exploration and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.
We utilize third-party services to maximize the efficiency of our organization. The cost of oil field services may increase or decrease depending on the demand for services by other oil and gas companies. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations.
If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.
Our assets consist of a mix of reserves, with some being developed while others are undeveloped. To the extent that we sell the production of these reserves on a forward-looking basis but do not realize that anticipated level of production, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that storms or other unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the hedging contracts.
Our price risk management activities could result in financial losses or could reduce our income, which may adversely affect our cash flows.
We enter into derivative contracts to reduce the impact of oil and natural gas price volatility on our cash flow from operations. Currently, we use a combination of crude oil and natural gas put, swap and collar arrangements to mitigate the volatility of future oil and natural gas prices received on our production.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial decrease in our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our price risk management activities are subject to the following risks:
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• | a counterparty may not perform its obligation under the applicable derivative instrument; |
• | production is less than expected; |
• | there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received; and |
• | the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures. |
During periods of declining commodity prices, our commodity price derivative positions increase, which increases our counterparty exposure.
Ultra-deep trend wells may require equipment that may delay development and incur longer drilling times, which may increase costs.
We have participated in eight ultra-deep wells to date with our participations ranging from approximately 9% to 23%. These projects have similar geological characteristics as deepwater prospects with a potential for significant reserves. The ultra-deep wells are some of the deepest wells ever drilled in the world and are subject to very high pressures and temperatures. The drilling, logging and completion techniques are near the limits of existing technologies. As a result, new technologies and techniques are being developed to deal with these challenges. The use of advanced drilling technologies involves a higher risk of technological failure and potentially higher costs. In addition, there can be delays in completion due to necessary equipment that is specially ordered to handle the challenges of ultra-deep wells.
Deepwater operations present special risks that may adversely affect the cost and timing of reserve development.
Currently, we have minority, non-operated interests in four deepwater fields. We may evaluate additional activity in the deepwater Gulf of Mexico in the future. Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present on the shelf. As a result, a considerable amount of time may elapse between a deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.
We may be unable to successfully integrate the operations of the properties or businesses we acquire.
Integration of the operations of the properties we acquire with our existing business is a complex, time-consuming and costly process. Failure to successfully integrate the acquired businesses and operations in a timely manner may have a material adverse effect on our business, financial condition, results of operations and cash flows. The difficulties of combining the acquired operations include, among other things:
• | operating a larger organization; |
• | coordinating geographically disparate organizations, systems and facilities; |
• | integrating corporate, technological and administrative functions; |
• | diverting management’s attention from other business concerns; |
• | diverting financial resources away from existing operations; |
• | increasing our indebtedness; and |
• | incurring potential environmental or regulatory liabilities and title problems. |
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The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.
In addition, we face the risk of identifying, competing for and pursuing other acquisitions, which takes time and expense and diverts management’s attention from other activities.
We may not realize all of the anticipated benefits from our acquisitions.
We may not realize all of the anticipated benefits from our current and future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices, including with respect to commodity prices such as for oil and natural gas.
For example, following the EPL Acquisition, commodity prices significantly declined, and we have experienced a sustained low commodity price environment. As a result of the significant decline in commodity prices, we have not realized the revenue enhancements that we originally anticipated from the EPL Acquisition and have substantial additional debt to service that was incurred in connection with funding the EPL Acquisition.
The properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the acquired properties or obtain protection from sellers against such liabilities.
Our business strategy includes a continuing acquisition program, which may include acquisitions of exploration and production companies, producing properties and undeveloped leasehold interests. The successful acquisition of oil and natural gas properties requires assessments of many factors that are inherently inexact and may be inaccurate, including the following:
• | acceptable prices for available properties; |
• | amounts of recoverable reserves; |
• | estimates of future oil and natural gas prices; |
• | estimates of future exploratory, development and operating costs; |
• | estimates of the costs and timing of plugging and abandonment; and |
• | estimates of potential environmental and other liabilities. |
Our assessment of the acquired properties will not reveal all existing or potential problems nor will it permit us to become familiar enough with the properties to fully assess their capabilities and deficiencies. In the course of our due diligence, we historically have not physically inspected every well, platform or pipeline. Even if we had physically inspected each of these, our inspections may not have revealed structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities associated with such risks. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. If an acquired property does not perform as originally estimated, we may have an impairment, which could have a material adverse effect on our financial position and results of operations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration and oil spill response plans, and other related restrictions arising after the Deepwater Horizon incident in the Gulf of Mexico may have a material adverse effect on our business, financial condition, or results of operations.
In response to the Deepwater Horizon incident in the Gulf of Mexico in April 2010, BSEE and BOEM, each agencies of the U.S. Department of the Interior, have imposed new and more stringent permitting
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procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. These governmental agencies have also implemented and enforced new rules, Notices to Lessees and Operators and temporary drilling moratoria that imposed safety and operational performance measures on exploration, development and production operators in the Gulf of Mexico or otherwise resulted in a temporary cessation of drilling activities. Compliance with these added and more stringent regulatory restrictions in addition to any uncertainties or inconsistencies in current decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development and oil spill response plans could adversely affect or delay new drilling and ongoing development efforts. Moreover, these governmental agencies are continuing to evaluate aspects of safety and operational performance in the Gulf of Mexico and, as a result, are developing and implementing new, more restrictive requirements such as, for example, the 2013 amendments to the federal Workplace Safety Rule regarding the utilization of a more comprehensive safety and environmental management system, (“SEMS”), which amended rule is sometimes referred to as SEMS II, and, more recently, the August 2014 Advanced Notice of Proposed Rulemaking that ultimately seeks to bolster the offshore financial assurance and bonding program.
Among other adverse impacts, these additional measures could delay or disrupt our operations, increase the risk of expired leases due to the time required to develop new technology, result in increased supplemental bonding requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities. If similar material spill incidents were to occur in the future, the United States or other countries could elect again to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development. We cannot predict the full impact of any new laws or regulations on our drilling operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.
Further, the deepwater areas of the Gulf of Mexico (as well as international deepwater locations) lack the degree of physical and oilfield service infrastructure present in shallower waters. Therefore, despite our oil spill response capabilities, it may be difficult for us to quickly or effectively execute any contingency plans related to future events similar to the Deepwater Horizon incident. The matters described above, individually or in the aggregate, could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
If we are unable to acquire or renew permits and approvals required for operations, we may be forced to suspend or cease operations altogether.
The construction and operation of energy projects require numerous permits and approvals from governmental agencies. In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years. We may not be able to obtain all necessary permits and approvals or obtain them in a timely manner, and as a result our operations may be adversely affected. In addition, obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse changes in the interpretation of existing permits and approvals, and these may create a risk of expensive delays or loss of value if a project is unable to proceed as planned due to changing requirements or local opposition.
Our operations are subject to environmental and other government laws and regulations that are costly and could potentially subject us to substantial liabilities.
As described in more detail below, our business activities are subject to regulation by multiple federal, state and local governmental agencies. Our historical and projected operating costs reflect the recurring costs resulting from compliance with these regulations, and we do not anticipate material expenditures in excess of these amounts in the absence of future acquisitions or changes in regulation, or discovery of existing but unknown compliance issues. Additional proposals and proceedings that affect the oil and gas industries are regularly considered by Congress, the states, regulatory commissions and agencies, and the courts. We cannot predict when or whether any such proposals may become effective or the magnitude of the impact changes in laws and regulations may have on our business; however, additions or enhancements to the regulatory burden on our industry generally increase the cost of doing business and affect our profitability.
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Our oil and gas exploration, production, and related operations are subject to extensive rules and regulations promulgated by federal, state, and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases our cost of doing business and affects our profitability. Because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws.
All of the jurisdictions in which we operate generally require permits for drilling operations, drilling bonds, and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such jurisdictions also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain jurisdictions also limit the rate at which oil and gas can be produced from our properties.
FERC regulates interstate natural gas transportation rates and terms of service, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. FERC has implemented regulations establishing an indexing methodology for interstate transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability.
Although FERC has not made any formal determinations with respect to any of our facilities, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine if a pipeline is a gathering pipeline and are therefore not subject to FERC’s jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, however, and, over time, FERC’s policy for determining which facilities it regulates has changed. In addition, the distinction between FERC-regulated transmission facilities, on the one hand, and gathering facilities, on the other, is a fact-based determination made by FERC on a case-by-case basis. If FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act of 1978 (NGPA). Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided
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services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by FERC.
State regulation of gathering facilities includes safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation. Our gathering operations may also be subject to state ratable take and common purchaser statutes, designed to prohibit discrimination in favor of one producer over another or one source of supply over another. State and local regulation may cause us to incur additional costs or limit our operations and can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.
Our oil and gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations:
• | require the acquisition of a permit before drilling commences; |
• | restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and |
• | impose substantial liabilities for pollution resulting from operations. |
Failure to comply with these laws and regulations may result in:
• | the imposition of administrative, civil and/or criminal penalties; |
• | incurring investigatory or remedial obligations; and |
• | the imposition of injunctive relief, which could limit or restrict our operations. |
Changes in environmental laws and regulations or how they are interpreted or applied occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to be in compliance in all material respects with all applicable environmental laws and regulations, we cannot assure shareholders that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability.
Under certain environmental laws that impose strict, joint and several liability, we could be held liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination, and regardless of whether current or prior operations were conducted in compliance with all applicable laws and consistent with accepted standards of practice at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Such liabilities can be significant, and if imposed could have a material adverse effect on our financial condition or results of operations.
We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.
Rate regulation may not allow us to recover the full amount of increases in our costs.
We have ownership interests in oil pipelines that are subject to regulation by FERC. Rates for service on our system are set using FERC’s price indexing methodology. The indexing method currently allows a pipeline to increase its rates by a percentage factor equal to the change in the producer price index for
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finished goods plus 2.65 percent. When the index falls, we are required to reduce rates if they exceed the new maximum allowable rate. In addition, changes in the index might not be large enough to fully reflect actual increases in our costs.
FERC’s indexing methodology is subject to review every five years. The current or any revised indexing formula could hamper our ability to recover our costs because: (1) the indexing methodology is tied to an inflation index; (2) it is not based on pipeline-specific costs; and (3) it could be reduced in comparison to the current formula. Any of the foregoing would adversely affect our revenues and cash flow. FERC could limit our pipeline’s ability to set rates based on its costs, order our pipelines to reduce rates, require the payment of refunds or reparations to shippers, or any or all of these actions, which could adversely affect our financial position, cash flows, and results of operations. If FERC’s ratemaking methodology changes, the new methodology could also result in tariffs that generate lower revenues and cash flow.
Based on the way our oil pipelines are operated, we believe that the only transportation on our pipelines that is subject to the jurisdiction of FERC is the transportation specified in the tariff we have on file with FERC. We cannot guarantee that the jurisdictional status of transportation on our pipelines and related facilities will remain unchanged, however. Should circumstances change, then currently non-jurisdictional transportation could be found to be FERC-jurisdictional. In that case, FERC’s ratemaking methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs, and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, results of operations and financial condition.
If our tariff rates are successfully challenged, we could be required to reduce our tariff rates, which would reduce our revenues.
Shippers on our pipelines are free to challenge, or to cause other parties to challenge or assist others in challenging, our existing or proposed tariff rates. If any party successfully challenges our tariff rates, the effect would be to reduce revenues.
Our sales of oil and natural gas, and any hedging activities related to such energy commodities, expose us to potential regulatory risks.
FERC, the FTC and the CFTC hold statutory authority to regulate certain segments of the physical and futures energy commodities markets relevant to our business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil and natural gas, and any hedging activities related to these commodities, we are required to observe and comply with these anti-fraud and anti-manipulation regulations. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect our financial condition or results of operations.
We have identified material weaknesses in our internal controls that, if not properly corrected, could result in material misstatements in our financial statements.
Our management has identified material weaknesses in our internal control over financial reporting as of June 30, 2015. Further, we have determined that control deficiencies existed with respect to certain aspects of our historical financial reporting and, accordingly, we have concluded that our prior reports on disclosure controls and procedures may not have been correct and prior reports on internal control over financial reporting and changes in internal control over financial reporting may have been incorrect. A material weakness is a deficiency, or combination of deficiencies in internal controls over financial reporting that results in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
We did not maintain properly designed controls over the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program. Specifically, the controls in place relating to the documentation of hedge designations were not properly designed to provide reasonable assurance that these derivative contracts would be properly recorded and disclosed in the financial statements in accordance with U.S. GAAP. As a result, our controls failed to detect that our formal hedge documentation did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance
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with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Effective June 30, 2015, management discontinued the use of hedge accounting on all derivative contracts and does not expect the material weakness associated with hedge accounting to recur. If, in the future, we were to begin to designate our derivatives as hedges we would need to enhance our controls regarding consideration of all sources of ineffectiveness.
In addition, the Board has recently learned that, in 2007, 2009 and 2014, the Company’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provided the Company with services. The Board also learned that Norman Louie, one of our directors, made a personal loan to Mr. Schiller in 2014 before Mr. Louie became a director of the Company. At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of June 30, 2015, owned a majority interest in Energy XXI M21K and 6.3% of the Company’s common stock. The loans made in 2014 are still outstanding. Since Mr. Schiller did not disclose the personal loans before they were made, the Board has determined that he did not comply with the procedural requirements of the Company’s Code of Business Conduct and Ethics. Upon learning of Mr. Schiller’s personal loans from affiliates of service providers, the Board engaged independent legal counsel to conduct an internal investigation, with the assistance of outside forensic accountants, to review these loans and the Company’s vendor procurement processes. The Board is still reviewing the results of the internal investigation. Although the internal investigation has not uncovered any illegal activity or any impact on the Company’s financial reporting or financial statements, the Company concluded this non-compliance to be a material weakness in its control environment given the leadership position of this officer, the visibility and importance of his actions to the Company’s overall system of controls and the significance with which the Company views this nondisclosure. As part of its review, the Board has begun the process of designing and implementing additional controls and procedures, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise from Mr. Schiller’s personal loans; revising the Code of Business Conduct and Ethics to explicitly ban any such personal loans in the future; and implementing an enhanced comprehensive training program on the Company’s Code of Business Conduct and Ethics.
If we are not able to remedy the control deficiencies in a timely manner, we may be unable to provide holders of our securities with the required financial information in a timely and reliable manner, either of which could subject us to litigation and regulatory enforcement actions.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
The EPA has determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (“CAA”). Among the EPA’s rules regulating greenhouse gas emissions under the CAA, one requires a reduction in emissions of greenhouse gases from motor vehicles and requires preconstruction and operating permits for certain large stationary sources of such emissions. The EPA has also adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including petroleum refineries and certain onshore oil and natural gas production facilities. In addition, in January 2015, the Obama Administration announced its goal to reduce methane emissions from the oil and gas sector by 40 to 45% from 2012 emission levels by 2025. As part of this announcement, the EPA announced that it will issue a proposed rule in the summer of 2015 and a final rule in 2016 setting standards for methane and volatile organic compounds emissions from new and modified oil and gas production sources and natural gas processing and transmission sources.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or
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regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances that correspond to their annual emissions of greenhouse gases. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. As the number of emission allowances declines each year, the cost or value of such allowances is expected to escalate significantly.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.
The adoption of financial reform legislation by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us that participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), was signed into law by President Obama on July 21, 2010 and requires the CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Dodd-Frank Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require certain counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The final rules will be phased in over time according to a specified schedule which is dependent on the finalization of certain other rules to be promulgated jointly by the CFTC and the SEC. The Dodd-Frank Act and any new regulations could increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas liquids and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas liquids and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.
Cyber incidents could result in information theft, data corruption, operational disruption, and/or financial loss.
The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering
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and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.
We depend on digital technology, including information systems and related infrastructure, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimated quantities of oil and gas reserves and for many other activities related to our business. Our business partners, including vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The complexity of the technologies needed to extract oil and gas in increasingly difficult physical environments, such as the ultra-deep trend, and global competition for oil and gas resources make certain information more attractive to thieves.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. Certain countries, including China, Russia and Iran, are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. SCADA-based systems are potentially more vulnerable to cyber-attacks due to the increased number of connections with office networks and the internet.
Our technologies, systems, networks, and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
• | unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources; |
• | data corruption, communication interruption, or other operational disruption during drilling activities could result in a dry hole cost or even drilling incidents; |
• | data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge; |
• | a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt one of our major development projects, effectively delaying the start of cash flows from the project; |
• | a cyber-attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues; |
• | a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues; |
• | a cyber-attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues; |
• | a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues; |
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• | a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and |
• | business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock. |
Although to date we have not experienced any losses relating to cyber-attacks, there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
We may be taxed as a United States corporation.
Energy XXI Ltd is incorporated under the laws of Bermuda because of our long-term desire to have business interests outside the United States. Currently, legislation in the United States that penalizes domestic corporations that reincorporate in a foreign country does not affect us, but future legislation could.
We plan to purchase any U.S. assets through our wholly owned subsidiary Energy XXI, Inc. and its subsidiaries, who will pay U.S. taxes on U.S. income. Energy XXI Ltd does not currently intend to engage in any business activity in the United States. However, there is a risk that some or all of our income could be challenged, and considered as effectively connected to a U.S. trade or business, and therefore subject to U.S. taxation. In consideration of this risk, Energy XXI Ltd and its U.S. subsidiaries have implemented certain operational steps to separate the U.S. operations from our other operations. In general, employees based in the United States will be employees of our U.S. subsidiaries, and will be paid for their services by such U.S. subsidiaries. Salaries of our employees who are U.S. residents and who render services to the U.S. business activities will be allocated as expenses of the U.S. subsidiaries.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
The Budget for Fiscal Year 2016 sent to Congress by President Obama on February 2, 2015, among other proposed legislation, contains recommendations that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. Several bills have been introduced in Congress that would implement these proposals. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such changes could have an adverse effect on our financial position, results of operations and cash flows.
U.S. persons who own our common shares may have more difficulty in protecting their interests than U.S. persons who are shareholders of a U.S. corporation.
The rights of shareholders under Bermuda law are not as extensive as the rights of shareholders under legislation or judicial precedent in many U.S. jurisdictions. Class actions and derivative actions are generally not available to shareholders under the laws of Bermuda. However, the Bermuda courts ordinarily would be expected to follow English case law precedent, which would permit a shareholder to commence an action in the name of a company to remedy a wrong done to a company where the act complained of is alleged to be beyond the corporate power of a company, is illegal or would result in the violation of our memorandum of association or bye-laws. Furthermore, consideration would be given by the court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of our shareholders than actually approved it. The winning party in such an action generally would be able to recover a portion of attorneys’ fees incurred in connection with such action. Our bye-laws provide that shareholders waive all claims or rights of action that they might have, individually or in the right of the Company, against any director or officer for any act or failure to act in the performance of such director’s or
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officer’s duties, except with respect to any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to stockholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.
Our bye-laws contain provisions that discourage corporate takeovers and could prevent shareholders from realizing a premium on their investment.
Our bye-laws contain provisions that could delay or prevent changes in our management or a change of control that a shareholder might consider favorable. For example, they may prevent a shareholder from receiving the benefit from any premium over the market price of our common shares offered by a bidder in a potential takeover. Even in the absence of a takeover attempt, these provisions may adversely affect the prevailing market price of our common shares if they are viewed as discouraging takeover attempts in the future. For example, provisions in our bye-laws that could delay or prevent a change in management or change in control include:
• | the board is permitted to issue preferred shares and to fix the price, rights, preferences, privileges and restrictions of the preferred shares without any further vote or action by our shareholders; |
• | election of our directors is staggered, meaning that the members of only one of three classes of our directors are elected each year; |
• | shareholders have limited ability to remove directors; and |
• | in order to nominate directors at shareholder meetings, shareholders must provide advance notice and furnish certain information with respect to the nominee and any other information as may be reasonably required by the Company. |
These provisions, alone or in combination with each other, may discourage transactions involving actual or potential changes of control, including transactions that otherwise could involve payment of a premium over prevailing market prices to stockholders for their common shares.
The impact of Bermuda’s letter of commitment to the Organisation for Economic Co-operation and Development to eliminate harmful tax practices is uncertain and could affect our tax status in Bermuda.
Bermuda has implemented a legal and regulatory regime that the Organisation for Economic Co-operation and Development (“OECD”) has recognized as generally complying with internationally agreed standards for transparency and exchange of information for tax purposes. This standard has involved Bermuda entering into a number of bilateral tax information exchange agreements which provide that upon request the competent authorities of participating countries shall provide assistance through the exchange of information relevant to the administration or enforcement of domestic laws of the participating countries concerning taxes covered by the agreements without regard to any domestic tax interest requirement or bank secrecy for tax purposes. This includes information that is relevant to the determination, assessment and collection of such taxes, the recovery and enforcement of tax claims or the investigation or prosecution of tax matters. Information is to be exchanged in accordance with the agreements and shall be treated as confidential in the manner provided therein. Consequently, shareholders should be aware that in accordance with such arrangements (as extended or varied from time to time to comply with the current international standards, to the extent adopted by Bermuda or any other relevant jurisdiction), relevant information concerning it and/or its investment in the Company may be provided to the competent authority of a jurisdiction with which Bermuda has entered a tax information exchange agreement (or equivalent).
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is included in Item 1 “Business” of this Form 10-K.
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Item 3. Legal Proceedings
We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material adverse effect on our financial position, results of operations or cash flows.
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information for Common Stock
On August 1, 2007, our common stock was admitted for trading on The NASDAQ Capital Market under the symbol “EXXI.” On August 12, 2011, our common stock was admitted for trading on the Nasdaq Global Select Market (“NASDAQ”) and continues to trade under the symbol “EXXI.” The following table sets forth, for the periods indicated, the range of the high and low closing sales prices of our common stock as reported on the NASDAQ.
Unrestricted Common Stock | ||||||||
High | Low | |||||||
Fiscal 2014 | ||||||||
First Quarter | $ | 30.02 | $ | 22.17 | ||||
Second Quarter | 32.45 | 25.15 | ||||||
Third Quarter | 25.86 | 21.22 | ||||||
Fourth Quarter | 24.01 | 20.29 | ||||||
Fiscal 2015 | ||||||||
First Quarter | 23.55 | 11.35 | ||||||
Second Quarter | 11.13 | 2.45 | ||||||
Third Quarter | 4.83 | 2.33 | ||||||
Fourth Quarter | 4.61 | 2.63 |
As of September 15, 2015, there were approximately 463 holders of record of our common stock.
Dividend Information
We paid cash dividends of $0.01 per share to holders of our common stock on March 13, 2015 and June 12, 2015. We paid cash dividends of $0.12 per share to holders of our common stock on September 12, 2014 and December 12, 2014. We paid quarterly cash dividends of $0.12 per share to holders of our common stock during the year ended June 30, 2014.
Cash dividends on our common stock were not approved and will not be paid for the first quarter of fiscal year 2016 and are not expected to be paid in the foreseeable future. The covenants in certain debt instruments to which we are a party place certain restrictions and conditions on our ability to pay dividends. Any future cash dividends would depend on contractual limitations, future earnings, capital requirements, our financial condition and other factors determined by our Board of Directors.
Purchases of Equity Securities
Repurchases of Common Stock
In May 2013, our Board of Directors approved a stock repurchase program authorizing us to repurchase up to $250 million in value of our common stock for an extended period of time, in one or more open market transactions. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity and other appropriate factors. The repurchase program does not obligate us to acquire any particular amount of common stock and may be modified or suspended at any time and could be terminated prior to completion. The repurchase program will be funded with cash on hand or borrowings under our revolving credit facility. Any repurchased shares of common stock will be retained at the subsidiary level, subject to transfer to the parent company where they may be retired.
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In connection with the repurchase program, our Board of Directors also approved a Rule 10b5-1 plan that allows us to repurchase common stock at times when it otherwise might be prevented from doing so under insider trading laws or because of self-imposed trading blackout periods. A broker selected by us has the authority under the pricing parameters and other terms and limitations specified in the 10b5-1 plan to repurchase shares on our behalf.
In November 2013, concurrently with the offering of our 3.0% Senior Convertible Notes due 2018, our Board of Directors approved an additional one time repurchase of our common stock of approximately $76 million, pursuant to which one of the Company’s wholly-owned subsidiaries repurchased 2,776,200 shares of the Company’s common stock for approximately $76 million, at a weighted average price per share, excluding fees, of $27.39.
We have not made any repurchases under our repurchase program during the fiscal year ended June 30, 2015, and we have suspended the repurchase program indefinitely to reduce our capital needs.
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Item 6. Selected Financial Data
The following information as of and for the years ended June 30, 2014, 2013, 2012, and 2011 has been updated to reflect the restatement to our financial statements as discussed in Note 22– Restatement of Previously Issued Consolidated Financial Statements of Notes to Consolidated Financial Statements in this Form 10-K. The amounts for prior periods presented in this report have been restated primarily to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) to gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. The following table sets forth a reconciliation of previously reported and restated net income (loss) and accumulated deficit as of the dates and for the periods shown (in thousands):
Net Income (Loss) | Accumulated Deficit | |||||||||||||||||||
Year Ended June 30, | At June 30, 2010 | |||||||||||||||||||
2014 | 2013 | 2012 | 2011 | |||||||||||||||||
(In thousands) | ||||||||||||||||||||
Previously reported | $ | 59,111 | $ | 162,081 | $ | 335,827 | $ | 64,655 | $ | (492,867 | ) | |||||||||
Pre-tax adjustments: | ||||||||||||||||||||
Change in accounting for derivative financial instruments | (72,348 | ) | (47,770 | ) | 193,980 | (147,984 | ) | 42,660 | ||||||||||||
Related impact on ceiling test impairment | — | — | — | — | (187,800 | ) | ||||||||||||||
Related impact on depreciation, depletion and amortization | 9,293 | 12,433 | 16,894 | 18,926 | 32,916 | |||||||||||||||
Total pre-tax adjustments | (63,055 | ) | (35,337 | ) | 210,874 | (129,058 | ) | (112,224 | ) | |||||||||||
Related income tax provision (benefit) | (22,069 | ) | (54,039 | ) | 67,893 | (51,794 | ) | 14,954 | ||||||||||||
Net after-tax adjustments | (40,986 | ) | 18,702 | 142,981 | (77,264 | ) | (127,178 | ) | ||||||||||||
Restated | $ | 18,125 | $ | 180,783 | $ | 478,808 | $ | (12,609 | ) | $ | (620,045 | ) |
You should read the selected consolidated historical financial information set forth below in conjunction with our restated Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our restated audited consolidated financial statements and the notes thereto included in Part II, Item 8, “Financial Statements and Supplementary Data,” of this Form 10-K.
We have derived the following selected consolidated financial information as of June 30, 2015 and 2014 and for the years ended June 30, 2015, 2014 and 2013 from the audited consolidated financial statements included in Part II, Item 8,“Financial Statements and Supplementary Data.”We have derived the selected consolidated financial information as of June 30, 2013, 2012 and 2011 and for the years ended June 30, 2012 and 2011 from our restated consolidated financial information.
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We have not amended our previously filed Annual Reports on Form 10-K or Quarterly Reports on Form 10-Q for the periods affected by the restatement. We have included in Part II, Item 8, “Financial Statements and Supplementary Data,” restated quarterly financial statements for the three months ended September 30, 2014 and 2013 the three and six months ended December 31, 2014 and 2013, and the three and nine months ended March 31, 2015 and 2014. The financial information that has been previously filed or otherwise reported for these periods is superseded by the information in this Form 10-K, and the financial statements and related financial information contained in such previously filed reports should no longer be relied upon. These historical results are not necessarily indicative of results to be expected for any future periods.
Year Ended June 30, | ||||||||||||||||||||
2015 | 2014(1) (Restated) | 2013 (Restated) | 2012 (Restated) | 2011 (Restated) | ||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||
Income Statement Data | ||||||||||||||||||||
Revenues | $ | 1,405,452 | $ | 1,153,123 | $ | 1,158,932 | $ | 1,504,611 | $ | 716,950 | ||||||||||
Depreciation, depletion and amortization (“DD&A”) | 705,521 | 414,026 | 363,791 | 350,569 | 274,553 | |||||||||||||||
Impairment of oil and natural gas properties | 2,421,884 | — | — | — | — | |||||||||||||||
Goodwill impairment | 329,293 | — | — | — | — | |||||||||||||||
Operating income (loss) | (2,710,891 | ) | 217,806 | 326,081 | 694,158 | 79,865 | ||||||||||||||
Other (expense) – net | (336,297 | ) | (164,661 | ) | (112,704 | ) | (108,811 | ) | (132,006 | ) | ||||||||||
Net income (loss) | (2,433,838 | ) | 18,125 | 180,783 | 478,808 | (12,609 | ) | |||||||||||||
Basic earnings (loss) per common share | $ | (25.97 | ) | $ | 0.09 | $ | 2.14 | $ | 5.95 | $ | (0.75 | ) | ||||||||
Diluted earnings (loss) per common share | $ | (25.97 | ) | $ | 0.09 | $ | 1.94 | $ | 5.27 | $ | (0.75 | ) | ||||||||
Cash Flow Data | ||||||||||||||||||||
Provided by (used in) | ||||||||||||||||||||
Operating activities | $ | 330,753 | $ | 545,460 | $ | 638,148 | $ | 785,514 | $ | 387,725 | ||||||||||
Investing activities | ||||||||||||||||||||
Acquisitions | (301 | ) | (849,641 | ) | (161,164 | ) | (6,401 | ) | (1,012,262 | ) | ||||||||||
Investment in properties | (723,829 | ) | (788,676 | ) | (816,105 | ) | (570,670 | ) | (281,233 | ) | ||||||||||
Proceeds from the sale of properties | 261,931 | 126,265 | — | 2,750 | 38,431 | |||||||||||||||
Other | 1,751 | (32,523 | ) | (16,734 | ) | 4,728 | (8 | ) | ||||||||||||
Total investing activities | (460,448 | ) | (1,544,575 | ) | (994,003 | ) | (569,593 | ) | (1,255,072 | ) | ||||||||||
Financing activities | 740,737 | 1,144,921 | 238,768 | (127,241 | ) | 881,530 | ||||||||||||||
Increase (decrease) in cash | 611,042 | 145,806 | (117,087 | ) | 88,680 | 14,183 | ||||||||||||||
Dividends Paid per Common Share | $ | 0.26 | $ | 0.48 | $ | 0.33 | $ | 0.07 | $ | — |
June 30, | ||||||||||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | 2012 (Restated) | 2011 (Restated) | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Balance Sheet Data | ||||||||||||||||||||
Total assets | $ | 4,690,829 | $ | 7,341,497 | $ | 3,505,080 | $ | 3,011,882 | $ | 2,662,901 | ||||||||||
Long-term debt including current maturities | 4,608,432 | 3,759,644 | 1,370,045 | 1,018,344 | 1,113,387 | |||||||||||||||
Stockholders’ equity (deficit) | (728,722 | ) | 1,734,560 | 1,367,935 | 1,286,776 | 810,738 | ||||||||||||||
Common shares outstanding | 94,643 | 93,720 | 76,486 | 78,838 | 76,203 |
(1) | On June 3, 2014, we completed the EPL Acquisition which significantly increased our scope of operation. See Note 3 — “Acquisitions and Dispositions” to our Consolidated Financial Statements in this Form 10-K. |
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Year Ended June 30, | ||||||||||||||||||||
Operating Highlights | 2015 | 2014 (Restated) | 2013 (Restated) | 2012 (Restated) | 2011 (Restated) | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||||||
Operating revenues | ||||||||||||||||||||
Oil sales | $ | 1,052,731 | $ | 1,104,208 | $ | 1,067,687 | $ | 1,186,193 | $ | 777,869 | ||||||||||
Natural gas sales | 117,282 | 135,883 | 112,753 | 88,608 | 101,813 | |||||||||||||||
Gain (loss) on derivative financial instruments | 235,439 | (86,968 | ) | (21,508 | ) | 229,809 | (162,732 | ) | ||||||||||||
Total revenues | 1,405,452 | 1,153,123 | 1,158,932 | 1,504,610 | 716,950 | |||||||||||||||
Percentage of operating revenues from crude oil | ||||||||||||||||||||
Prior to gain (loss) on derivative financial instruments | 90 | % | 89 | % | 90 | % | 93 | % | 88 | % | ||||||||||
Operating expenses | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | 40,046 | 31,183 | 32,737 | 28,521 | 27,876 | |||||||||||||||
Workover and maintenance | 65,562 | 66,481 | 65,118 | 56,413 | 33,095 | |||||||||||||||
Direct lease operating expense | 357,927 | 268,083 | 239,308 | 225,881 | 178,507 | |||||||||||||||
Total lease operating expense | 463,535 | 365,747 | 337,163 | 310,815 | 239,478 | |||||||||||||||
Production taxes | 8,385 | 5,427 | 5,246 | 7,261 | 3,336 | |||||||||||||||
Gathering and transportation | 21,144 | 23,532 | 24,168 | 16,371 | 12,499 | |||||||||||||||
DD&A | 705,521 | 414,026 | 363,791 | 350,569 | 274,553 | |||||||||||||||
Accretion of asset retirement obligations | 50,081 | 30,183 | 30,885 | 39,161 | 32,127 | |||||||||||||||
Impairment of oil and natural gas properties | 2,421,884 | — | — | — | — | |||||||||||||||
Goodwill impairment | 329,293 | — | — | — | — | |||||||||||||||
General and administrative | 116,500 | 96,402 | 71,598 | 86,276 | 75,091 | |||||||||||||||
Total operating expenses | 4,116,343 | 935,317 | 832,851 | 810,453 | 637,084 | |||||||||||||||
Operating income (loss) | $ | (2,710,891 | ) | $ | 217,806 | $ | 326,081 | 694,157 | 79,866 | |||||||||||
Sales volumes per day | ||||||||||||||||||||
Natural gas (MMcf) | 102.7 | 89.7 | 88.6 | 81.5 | 67.2 | |||||||||||||||
Crude oil (MBbls) | 41.8 | 30.1 | 28.3 | 30.5 | 23.4 | |||||||||||||||
Total (MBOE) | 58.9 | 45 | 43.1 | 44.1 | 34.6 | |||||||||||||||
Percent of sales volumes from crude oil | 71 | % | 67 | % | 66 | % | 69 | % | 68 | % | ||||||||||
Average sales price | ||||||||||||||||||||
Oil per Bbl | $ | 68.99 | $ | 100.59 | $ | 103.48 | $ | 106.17 | $ | 90.95 | ||||||||||
Natural gas per Mcf | 3.13 | 4.15 | 3.48 | 2.97 | 4.15 | |||||||||||||||
Gain (loss) on derivative financial instruments per BOE | 10.95 | (5.29 | ) | (1.37 | ) | 14.24 | (12.87 | ) | ||||||||||||
Total revenues per BOE | 65.36 | 70.16 | 73.77 | 93.21 | 56.71 | |||||||||||||||
Operating expenses per BOE | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | 1.86 | 1.90 | 2.08 | 1.77 | 2.21 | |||||||||||||||
Workover and maintenance | 3.05 | 4.04 | 4.15 | 3.49 | 2.62 | |||||||||||||||
Direct lease operating expense | 16.64 | 16.31 | 15.23 | 13.99 | 14.12 | |||||||||||||||
Total lease operating expense per BOE | 21.55 | 22.25 | 21.46 | 19.25 | 18.95 | |||||||||||||||
Production taxes | 0.39 | 0.33 | 0.33 | 0.45 | 0.26 | |||||||||||||||
Gathering and transportation | 0.98 | 1.43 | 1.54 | 1.01 | 0.99 | |||||||||||||||
DD&A | 32.81 | 25.19 | 23.16 | 21.72 | 21.72 | |||||||||||||||
Accretion of asset retirement obligations | 2.33 | 1.84 | 1.97 | 2.43 | 2.54 | |||||||||||||||
Impairment of oil and natural gas properties | 112.63 | — | — | — | — | |||||||||||||||
Goodwill impairment | 15.31 | — | — | — | — | |||||||||||||||
General and administrative | 5.42 | 5.87 | 4.56 | 5.34 | 5.94 | |||||||||||||||
Total operating expenses per BOE | 191.42 | 56.91 | 53.02 | 50.20 | 50.40 | |||||||||||||||
Operating income (loss) per BOE | $ | (126.06 | ) | $ | 13.25 | $ | 20.75 | $ | 43.01 | $ | 6.31 |
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Quarter Ended | ||||||||||||||||||||
Operating Highlights | June 30, 2015 | March 31, 2015 (Restated) | December 31, 2014 (Restated) | September 30, 2014 (Restated) | June 30, 2014 (Restated) | |||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||||||
Operating revenues | ||||||||||||||||||||
Oil sales | $ | 225,263 | $ | 177,605 | $ | 279,708 | $ | 370,155 | $ | 294,975 | ||||||||||
Natural gas sales | 23,908 | 27,012 | 31,801 | 34,561 | 34,599 | |||||||||||||||
Gain (loss) on derivative financial instruments | (29,711 | ) | 16,963 | 191,462 | 56,725 | (28,266 | ) | |||||||||||||
Total revenues | 219,460 | 221,580 | 502,971 | 461,441 | 301,308 | �� | ||||||||||||||
Percentage of operating revenues from crude oil | ||||||||||||||||||||
Prior to gain (loss) on derivative financial instruments | 90 | % | 87 | % | 90 | % | 91 | % | 90 | % | ||||||||||
Operating expenses | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | 8,963 | 8,828 | 11,233 | 11,022 | 8,357 | |||||||||||||||
Workover and maintenance | 12,243 | 10,773 | 13,130 | 29,416 | 14,408 | |||||||||||||||
Direct lease operating expense | 72,268 | 88,509 | 95,003 | 102,147 | 79,806 | |||||||||||||||
Total lease operating expense | 93,474 | 108,110 | 119,366 | 142,585 | 102,571 | |||||||||||||||
Production taxes | 1,492 | 1,537 | 2,263 | 3,093 | 1,750 | |||||||||||||||
Gathering and transportation | 3,459 | 3,726 | 4,771 | 9,188 | 6,509 | |||||||||||||||
DD&A | 183,279 | 187,947 | 175,155 | 159,140 | 117,503 | |||||||||||||||
Accretion of asset retirement obligations | 12,358 | 12,106 | 12,798 | 12,819 | 9,366 | |||||||||||||||
Impairment of oil and natural gas properties | 1,852,268 | 569,616 | — | — | — | |||||||||||||||
Goodwill impairment | — | — | 329,293 | — | — | |||||||||||||||
General and administrative | 25,210 | 37,121 | 27,745 | 26,424 | 30,824 | |||||||||||||||
Total operating expenses | 2,171,540 | 920,163 | 671,391 | 353,249 | 268,523 | |||||||||||||||
Operating income (loss) | $ | (1,952,080 | ) | $ | (698,583 | ) | $ | (168,420 | ) | $ | 108,192 | 32,785 | ||||||||
Sales volumes per day | ||||||||||||||||||||
Natural gas (MMcf) | 103.2 | 110.4 | 96.5 | 100.7 | 84.8 | |||||||||||||||
Crude oil (MBbls) | 42.0 | 41.6 | 41.8 | 41.8 | 32.0 | |||||||||||||||
Total (MBOE) | 59.3 | 60.0 | 57.9 | 58.6 | 46.1 | |||||||||||||||
Percent of sales volumes from crude oil | 71 | % | 69 | % | 72 | % | 71 | % | 69 | % | ||||||||||
Average sales price | ||||||||||||||||||||
Oil per Bbl | $ | 58.87 | $ | 47.49 | $ | 72.70 | $ | 96.28 | $ | 101.45 | ||||||||||
Natural gas per Mcf | 2.55 | 2.72 | 3.58 | 3.73 | 4.48 | |||||||||||||||
Gain (loss) on derivative financial instruments per BOE | (5.51 | ) | 3.14 | 35.94 | 10.53 | (6.74 | ) | |||||||||||||
Total revenues per BOE | 40.70 | 41.06 | 94.40 | 85.64 | 71.84 | |||||||||||||||
Operating expenses per BOE | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | 1.66 | 1.64 | 2.11 | 2.05 | 1.99 | |||||||||||||||
Workover and maintenance | 2.27 | 2.00 | 2.46 | 5.46 | 3.44 | |||||||||||||||
Direct lease operating expense | 13.40 | 16.40 | 17.83 | 18.96 | 19.03 | |||||||||||||||
Total lease operating expense per BOE | 17.33 | 20.04 | 22.40 | 26.47 | 24.46 | |||||||||||||||
Production taxes | 0.28 | 0.28 | 0.42 | 0.57 | 0.42 | |||||||||||||||
Gathering and transportation | 0.64 | 0.69 | 0.90 | 1.71 | 1.55 | |||||||||||||||
DD&A | 33.99 | 34.83 | 32.87 | 29.54 | 28.02 | |||||||||||||||
Accretion of asset retirement obligations | 2.29 | 2.24 | 2.40 | 2.38 | 2.23 | |||||||||||||||
Impairment of oil and natural gas properties | 343.52 | 105.56 | — | — | — | |||||||||||||||
Goodwill impairment | — | — | 61.80 | — | — | |||||||||||||||
General and administrative | 4.68 | 6.88 | 5.21 | 4.90 | 7.35 | |||||||||||||||
Total operating expenses per BOE | 402.73 | 170.52 | 126.00 | 65.57 | 64.03 | |||||||||||||||
Operating income (loss) per BOE | $ | (362.03 | ) | $ | (129.46 | ) | $ | (31.60 | ) | $ | 20.07 | $ | 7.81 |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with Item 8, “Financial Statements and Supplementary Data” of this Form 10-K. The following discussion includes forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Known material factors that could cause or contribute to such differences include those discussed under Part I, Item 1A “Risk Factors” in this Form 10-K.
Restatement of Previously Issued Consolidated Financial Statements
Management’s Discussion and Analysis of Financial Condition and Results of Operations have been updated to reflect the effects of the restatement described in Note 22 — Restatement of Previously Issued Consolidated Financial Statements of Notes to Consolidated Financial Statements in this Form 10-K. We have also included a discussion of restated revenues for the three unaudited quarters of fiscal 2015 and fiscal 2014 following the discussion of our results of operations for our year ended June 30, 2015 compared to the year ended June 30, 2014 below. In addition, we have also included our restated financial statements for the three unaudited quarters of fiscal 2015 following our fiscal year 2015 financial statements in Item 8, “Financial Statements and Supplementary Data — Restated Quarterly Financial Statements” in this Form 10-K.
In connection with preparing this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.
The consolidated financial statements for prior periods presented in this report have been restated primarily to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) to gain (loss) on derivative financial instruments in earnings and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment as described above. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. While these non-cash adjustments impact revenues, net income (loss) and net income (loss) attributable to common shareholders for each period, as well as total stockholders’ equity, these adjustments do not impact the economics of the hedge transactions nor do they affect our liquidity.
Overview
Energy XXI Ltd and its wholly-owned subsidiaries (“Energy XXI,” “us,” “we,” “our,” or “the Company”) is an independent oil and natural gas exploration and production company. With our principal operating subsidiary headquartered in Houston, Texas, we are engaged in the acquisition, development, operation and exploration of oil and natural gas properties onshore in Louisiana and on the Gulf of Mexico Shelf (“GoM Shelf”). Based on production volume, we are the largest publicly traded independent operator on the GoM Shelf. We intend to strengthen our position in a safe environment with a focus on delivering value for our shareholders.
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We are focused on 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 activities will provide us with an inventory of low-risk recompletion and extension opportunities in our geographic area of expertise.
On June 3, 2014, we completed the EPL Acquisition, pursuant to which we acquired all of EPL’s outstanding shares for total consideration of approximately $2.5 billion, including the assumption of EPL’s debt. The aggregate consideration received by EPL shareholders was paid 65% in cash and 35% in Energy XXI common shares and consisted of approximately $1.01 billion in cash and approximately 23.3 million common shares of Energy XXI. Upon closing, Energy XXI shareholders owned approximately 75% of the combined company and EPL shareholders owned the remaining 25%. The EPL Acquisition significantly increased our scope of operation. The EPL assets are located on the GoM Shelf and have been operationally integrated into our existing portfolio on the GoM Shelf.
During the second quarter of fiscal year 2015, oil prices began a substantial and rapid decline which has continued into the fiscal year 2016. In response to that decline, we initiated a series of financial and operational activities highlighted below.
• | Our fiscal year 2016 capital budget has been substantially reduced to a current planned amount of $130 to $150 million, as compared to actual capital expenditures in fiscal year 2015 (excluding acquisition activity) of approximately $649 million, and our fiscal year 2016 budget is focused on recompletion opportunities and lower risk development drilling opportunities in fields where we have had previous success, and eliminating capital commitments on exploration and other activities that do not provide incremental production. |
• | We have reduced field level operating costs, bringing lease operating costs per barrel down by 30% from fourth quarter of fiscal year 2014, and we have reduced general and administrative costs per barrel by approximately 36% from fourth quarter 2014 primarily through efficiencies and headcount reductions and continue to focus on operational and cost efficiencies. |
• | We have suspended dividends on our common stock for the foreseeable future. |
• | On March 12, 2015, we closed our private placement of $1.45 billion in aggregate principal amount of the 11.0% Notes for net proceeds of $1.35 billion, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds, $836 million was used to reduce our outstanding borrowings under our revolving credit facility to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015 and for fiscal year 2016. |
• | In connection with the issuance of the 11.0% Notes, we proactively amended our revolving credit facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants. |
• | On June 30, 2015, we sold the GIGS for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. In connection with the closing of the sale of the GIGS, we entered into a triple-net lease with Grand Isle Corridor pursuant to which we will continue to operate the GIGS. |
• | In addition, on June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. |
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• | During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million. Additionally, we repositioned our calendar 2015 hedging portfolio by putting on Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the then current commodity prices, which will provide us some price protection against further decline in oil prices. Subsequent to these transactions, we have some price protection under our hedging portfolio on approximately 27,000 barrels of crude oil per day representing approximately 70% of our estimated crude oil production volumes through December 2015 and some price protection on approximately 14,000 barrels of crude oil per day representing approximately 40% of our estimated crude oil production volumes in calendar 2016 under our hedging portfolio, which includes financially settled puts, put spreads, zero-cost collars and three-way collars. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk,” and in Note 10 — “Derivative Financial Instruments” to our Consolidated Financial Statements in this Form 10-K for a detailed discussion of our hedging program. |
In addition, in light of current commodity prices and our leverage position, we continue to analyze a variety of transactions and mechanisms designed to reduce debt, including the retirement or purchase of outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise and opportunistic acquisitions. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
At June 30, 2015, our total proved reserves were 183.5 MMBOE of which 75% were oil and 68% were classified as proved developed. We operated or had an interest in 567 gross producing wells on 388,199 net developed acres, including interests in 52 producing fields. We believe operating our assets is a key to our success and approximately 97% of our proved reserves are on properties operated by us. Our geographical concentration on the GoM Shelf enables us to manage the operated fields efficiently and our high number of wellbore locations provides diversification of our production and reserves.
Acquisition and Dispositions
Sale of the Grand Isle Gathering System
On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (altogether, and as previously defined, the “GIGS”) to Grand Isle Corridor, LP (“Grand Isle Corridor”), a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. (“CorEnergy) for cash consideration of $245 million, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the GIGS. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $248.9 million.
Additionally on June 30, 2015, in connection with the closing of the sale of the GIGS, we entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we will continue to operate the GIGS. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the GIGS. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the GIGS above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes.
Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the GIGS, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain
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obligations on Grand Isle Corridor, including confidentiality of information and keeping the GIGS free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the GIGS.
Sale of interests in the East Bay field
On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $68.9 million. We had acquired our interest in the East Bay field in the EPL Acquisition on June 3, 2014.
Purchase of interests in M21K, LLC
On August 11, 2015, we acquired all of the remaining equity interests of M21K, LLC (“M21K”) for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing. Prior to this transaction, we had owned a 20% interest in M21K through our investment in EXXI M21K, LLC (“EXXI M21K”). See Note 6 — “Equity Method Investments” to our Consolidated Financial Statements in this Form 10-K. Please also see Note 3 — “Acquisitions and Dispositions” and Note 21 — “Subsequent Events” to our Consolidated Financial Statements in this Form 10-K for more information regarding these transactions.
Ultra-Deep and Salt Play Activity
Ultra Deep. With our partner Freeport McMoRan Oil & Gas, LLC, we have participated in eight projects to date, both offshore and onshore, with our participation interests ranging from approximately 9% to 23%. The operator announced on December 24, 2014, that the Highlander well completed a successful production test, which was performed in the Cretaceous/Tuscaloosa section. The operator and its partners commenced production in late February 2015. A second well location has been identified and future plans will be determined pending review of performance of the first well. The operator has identified multiple prospects in the Highlander area which provide opportunities for future development of the field and controls rights to more than 50,000 gross acres. The field’s net production for the month of June 2015 of 0.5 MBOED accounted for approximately 1% of our net production. Net proved reserves for the field were 100% gas at June 30, 2015.
On February 1, 2013, we entered into an Exploration Agreement (the “Exploration Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central GoM Shelf. We have a 25% participation interest in the Exploration Agreement, which expires on February 1, 2018. The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through June 30, 2015. We expect to complete 3D seismic and WAZ seismic data processing in November 2015.
Known Trends and Uncertainties
Commodity Price Volatility. Prices for oil and natural gas historically have been volatile and are expected to continue to be volatile. Oil prices declined significantly during fiscal year 2015, and our ability to maintain current production levels could be impacted by continued downward pressure on oil prices. The posted price per barrel for West Texas intermediate light sweet crude oil, or WTI, for the period from July 1,
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2014 to June 30, 2015 ranged from a high of $105.34 to a low of $43.46, a decrease of 58.7%, and the NYMEX natural gas price per MMBtu for the period July 1, 2014 to June 30, 2015 ranged from a high of $4.49 to a low of $2.49, a decrease of 44.5%. As of September 22, 2015, the spot market price for WTI was $45.83. The recent declines in oil prices have adversely affected our financial position and results of operations and the quantities of oil and natural gas reserves that we can economically produce. If we experience sustained periods of low prices for oil and natural gas, it will likely have a further material adverse effect on our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital.
Decreasing Service Costs. We have also seen a significant and continuing reduction in rig rates and drilling costs, which should allow us to spend less capital drilling our development wells than in prior periods. Jack-up rig rates, for example, have fallen by 35 – 50% in recent months and other service providers are similarly cutting their rates.
Ceiling Test Write-down. For the third and fourth quarters of our fiscal year ended June 30, 2015, we recognized ceiling test write-downs of our oil and natural gas properties of $569.6 million and $1,852.3 million, respectively. The write-downs did not impact our cash flows from operating activities but did increase our net loss and reduce stockholders’ equity. Further ceiling test write-downs may be required if oil and natural gas prices remain low or decline further, unproved property values decrease, estimated proved reserve volumes are revised downward or the net capitalized cost of proved oil and gas properties otherwise exceeds the present value of estimated future net cash flows. Based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12 months ending September 30, 2015, we presently expect to incur further impairment of $900 million to $1,200 million in the first fiscal quarter of 2016. If the current low commodity price environment or downward trend in oil prices continues beyond first fiscal quarter of 2016, we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.
BOEM Bonding Requirements. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. We currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. We are undertaking a number of initiatives to mitigate our potential additional bonding requirements resulting from any waiver disqualifications and any forthcoming requirement from the BOEM and to limit the amount of additional required supplemental bonding by ensuring we have received credit for all of the plugging and abandonment work completed to date, by accounting for recent asset divestitures and consequential reduction in related bonding requirements such as the June 2015 sale of our interest in the East Bay field, and by counting our existing bonds and letters of credit with third parties against the BOEM’s various bonding requests. However, with respect to our existing bonds and letters of credit with third parties, we can provide no assurance that the BOEM will consider them when determining the total value of additional financial assurances and/or bonding we must provide. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding, generally as a result of exempt co-owners either losing their exemptions or no longer
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owning an interest in the property. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements.
Although we believe we are currently in compliance with the supplemental bonding requirements, the BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. Furthermore, the BOEM is actively seeking to adjust its financial assurance requirements for all companies operating in federal waters. The cost of compliance with our existing supplemental bonding requirements or any other changes to the BOEM’s current bonding requirements or regulations applicable to us or our properties could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases, and if we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended or terminated, and such action could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity. Please read “Risk Factors — We and our subsidiaries have been asked by the BOEM to obtain bonds or other surety in order to maintain compliance with BOEM regulations, which may be costly and could potentially reduce borrowings available under our revolving credit facility.”
Oil Spill Response Plan. We maintain a Regional Oil Spill Response Plan (the “Plan”) that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil Spill Response Plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. We believe the Plan specifications are consistent with the requirements set forth by the BSEE. Additionally, these plans are tested and drills are conducted periodically at all levels of the Company.
We have contracted with an emergency and spill response management consultant, to provide management expertise, personnel and equipment, under our supervision, in the event of an incident requiring a coordinated response. Additionally, we are a member of Clean Gulf Associates (“CGA”), a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico and has capabilities to simultaneously respond to multiple spills. CGA has chartered its marine equipment to the Marine Spill Response Corporation (“MSRC”), a private, not-for-profit marine spill response organization which is funded by the Marine Preservation Association, a member-supported, not-for-profit organization created to assist the petroleum and energy-related industries by addressing problems caused by oil spills on water. In the event of a spill, MSRC mobilizes appropriate equipment to CGA members. In addition, CGA maintains a contract with Airborne Support Inc., which provides aircraft and dispersant capabilities for CGA member companies.
Hurricanes. Since the majority of our production originates in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Significant hurricane impacts could include reductions and/or deferrals of future oil and natural gas production and revenues, increased lease operating expenses for evacuations and repairs and possible acceleration of plugging and abandonment costs.
Results of Operations
Year Ended June 30, 2015 Compared to the Restated Year Ended June 30, 2014
Our consolidated net loss attributable to common stockholders for the year ended June 30, 2015 was $2,445.7 million or $25.97 diluted net loss per common share (“per share”) as compared to consolidated net income attributable to common stockholders of $6.6 million or $0.09 diluted income per share for the year ended June 30, 2014. This decrease was primarily due to higher costs and expenses including impairment of oil and natural gas properties, impairment of goodwill, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes and gain on derivative financial instruments.
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Revenue Variances
Year Ended June 30, | Increase (Decrease) | Percent Increase (Decrease) | ||||||||||||||||||
2015 | 2014 (Restated) | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Oil | $ | 1,052,731 | $ | 1,104,208 | $ | (51,477 | ) | (4.7 | )% | |||||||||||
Natural gas | 117,282 | 135,883 | (18,601 | ) | (13.7 | )% | ||||||||||||||
Gain (loss) on derivative financial instruments | 235,439 | (86,968 | ) | 322,407 | (370.7 | )% | ||||||||||||||
Total Revenues | $ | 1,405,452 | $ | 1,153,123 | $ | 252,329 | 21.9 | % |
Revenues
Our consolidated revenues increased $252.3 million for the year ended June 30, 2015 as compared to the year ended June 30, 2014. Higher revenues were primarily due to higher oil sales volumes as a result of the EPL Acquisition and gain on derivative financial instruments, partially offset by lower commodity sales prices. Revenue variances related to commodity prices and sales volumes are presented in the following table and described below.
Price and Volume Variances
Year Ended June 30, | Increase (Decrease) | Percent Increase (Decrease) | Revenue Increase (Decrease) | |||||||||||||||||
2015 | 2014 (Restated) | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Price Variance | ||||||||||||||||||||
Oil sales prices (per Bbl)(1) | $ | 68.99 | $ | 100.59 | $ | (31.60 | ) | (31.4 | )% | $ | (346,353 | ) | ||||||||
Natural gas sales prices (per Mcf)(1) | 3.13 | 4.15 | (1.02 | ) | (24.6 | )% | (33,336 | ) | ||||||||||||
Gain (loss) on derivative financial instruments (per BOE) | 10.95 | (5.29 | ) | 16.24 | 322,407 | |||||||||||||||
Total price variance | (57,282 | ) | ||||||||||||||||||
Volume Variance | ||||||||||||||||||||
Oil sales volumes (MBbls) | 15,259 | 10,978 | 4,281 | 39.0 | % | 294,876 | ||||||||||||||
Natural gas sales volumes (MMcf) | 37,472 | 32,754 | 4,718 | 14.4 | % | 14,735 | ||||||||||||||
BOE sales volumes (MBOE) | 21,504 | 16,437 | 5,067 | 30.8 | % | |||||||||||||||
Percent of BOE from oil | 71 | % | 67 | % | ||||||||||||||||
Total volume variance | 309,611 | |||||||||||||||||||
Total price and volume variance | $ | 252,329 |
(1) | Commodity prices exclude the impact of derivative financial instruments. |
Price Variances
Commodity prices are one of the key drivers of our earnings and net operating cash flow. Lower commodity prices decreased revenues by $379.7 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014. Average oil prices decreased $31.60 per barrel in the year ended June 30, 2015, resulting in lower revenues of $346.4 million. Average natural gas prices decreased $1.02 per Mcf during the year ended June 30, 2015, resulting in lower revenues of $33.3 million. Our hedging activities partially offset the impact of the decrease in prices resulting in higher revenues of $322.4 million or $16.24 per BOE. The gain on derivatives for the year ended June 30, 2015 includes a gain on settlements and monetization of our derivative contracts of approximately $12.06 per barrel of oil compared to a loss on settlements of $1.58 per barrel of oil for the year ended June 30, 2014. Commodity prices are affected by many factors that are outside of our control, and we cannot accurately predict future commodity prices. Depressed commodity prices over an extended period of time could result in reduced cash from operating activities, potentially causing us to further reduce our capital expenditure program. Reductions in our capital expenditures could result in a reduction of production volumes.
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Volume Variances
Sales volumes are another key driver of our earnings and net operating cash flow. Oil sales volumes increased 11.7 MBbls per day in the year ended June 30, 2015 as compared to the prior fiscal year, resulting in higher revenues of $294.9 million. Natural gas sales volumes were also higher in the year ended June 30, 2015, increasing 12.9 MMcf per day for fiscal year 2015 as compared to the prior fiscal year, resulting in higher revenues of $14.7 million. The increase in sales volumes in the year ended June 30, 2015 was primarily due to production from assets acquired in the EPL Acquisition partially offset by the impact of natural decline.
Costs and expenses and other (income) expense
Year Ended June 30, | Increase (Decrease) Total $ | |||||||||||||||||||
2015 | 2014 (Restated) | |||||||||||||||||||
Total $ | Per BOE | Total $ | Per BOE | |||||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||||||
Cost and expenses | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | $ | 40,046 | $ | 1.86 | $ | 31,183 | $ | 1.90 | $ | 8,863 | ||||||||||
Workover and maintenance | 65,562 | 3.05 | 66,481 | 4.04 | (919 | ) | ||||||||||||||
Direct lease operating expense | 357,927 | 16.64 | 268,083 | 16.31 | 89,844 | |||||||||||||||
Total lease operating expense | 463,535 | 21.55 | 365,747 | 22.25 | 97,788 | |||||||||||||||
Production taxes | 8,385 | 0.39 | 5,427 | 0.33 | 2,958 | |||||||||||||||
Gathering and transportation | 21,144 | 0.98 | 23,532 | 1.43 | (2,388 | ) | ||||||||||||||
DD&A | 705,521 | 32.81 | 414,026 | 25.19 | 291,495 | |||||||||||||||
Accretion of asset retirement obligations | 50,081 | 2.33 | 30,183 | 1.84 | 19,898 | |||||||||||||||
Impairment of oil and natural gas properties | 2,421,884 | 112.63 | — | — | 2,421,884 | |||||||||||||||
Goodwill impairment | 329,293 | 15.31 | — | — | 329,293 | |||||||||||||||
General and administrative | 116,500 | 5.42 | 96,402 | 5.87 | 20,098 | |||||||||||||||
Total costs and expenses | $ | 4,116,343 | $ | 191.42 | $ | 935,317 | $ | 56.91 | $ | 3,181,026 | ||||||||||
Other (income) expense | ||||||||||||||||||||
(Income) loss from equity method investees | $ | 17,165 | $ | 0.80 | $ | 5,231 | $ | 0.32 | $ | 11,934 | ||||||||||
Other income – net | (4,176 | ) | (0.19 | ) | (3,298 | ) | (0.20 | ) | (878 | ) | ||||||||||
Interest expense | 323,308 | 15.03 | 162,728 | 9.90 | 160,580 | |||||||||||||||
Total other (income) expense | $ | 336,297 | $ | 15.64 | $ | 164,661 | $ | 10.02 | $ | 171,636 |
Costs and expenses increased $3.2 billion in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to the impairment of oil and gas properties, the impairment of goodwill and higher DD&A expense. We also had higher lease operating expense, general and administrative expenses and accretion of asset retirement obligations, principally due to the EPL Acquisition and other factors discussed further below.
At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at March 31, 2015 and June 30, 2015, we recognized ceiling test impairments of our oil and natural gas properties totaling $2,421.9 million during the year ended June 30, 2015.
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During the year ended June 30, 2015, we recorded a non-cash impairment charge of $329.3 million to reduce the carrying value of goodwill to zero as of December 31, 2014. At December 31, 2014, we performed a goodwill impairment test after assessing relevant events and circumstances, primarily the decline in oil prices since September 30, 2014. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill at December 31, 2014.
Lease operating expense increased $97.8 million in the year ended June 30, 2015 compared to the year ended June 30, 2014. This increase was primarily due to higher direct lease operating expenses stemming from the increase in producing properties resulting from acquisitions and from our capital program, partially offset by declining service costs in the last three quarters of fiscal year 2015 resulting from the decline in commodity prices and decrease in demand for oil field services. Lease operating expense per BOE declined from $22.25 for the year ended June 30, 2014 to $21.55 for the year ended June 30, 2015.
DD&A expense increased $291.5 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014. DD&A expense increased $166.2 million as a result of higher net production. This was coupled with an increase in the DD&A per BOE rate of $7.62, which increased DD&A expense by $125.3 million. The increase in the DD&A rate in the year ended June 30, 2015 was due to the EPL Acquisition, the reclassification of exploratory wells in progress to evaluated properties and a reduction in proved reserve estimates.
Accretion of asset retirement obligations increased $19.9 million in the year ended June 30, 2015 as compared to the prior fiscal year. This increase was principally due to accretion of asset retirement obligations assumed in connection with the EPL Acquisition.
General and administrative expense increased $20.1 million in the year ended June 30, 2015 as compared to the prior fiscal year, primarily due to executive and employee severance costs totaling approximately $17.6 million and consulting fees associated with the integration of EPL.
Other (income) expense increased $171.6 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to higher interest expense due to increased borrowings. Interest expense increased $160.6 million in the year ended June 30, 2015 as compared to the year ended June 30, 2014, principally due to debt incurred and assumed in connection with the EPL Acquisition, the issuance of the 11.0% Notes and the write-off of a portion of the deferred debt issue costs associated with our revolving credit facility. On a per unit of production basis, interest expense increased 51.8%, from $9.90 per BOE to $15.03 per BOE.
Income Tax Expense
We recorded income tax benefit of $613.4 million in the year ended June 30, 2015 compared to income tax expense of $35.0 million recorded in the year ended June 30, 2014. The effective income tax expense/(benefit) rate for the year ended June 30, 2015 is (20.1%) as compared to 65.9% for the year ended June 30, 2014. The decrease in the tax rate is primarily due: (i) the book loss for the year, (ii) the $329 million non-tax deductible goodwill impairment, and (iii) the $356.8 million increase in our valuation allowance. This increase in our valuation allowance was due to changes in our expectations regarding our future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments). In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition did not have tax basis; therefore, the goodwill impairment is nondeductible for tax purposes. See Note 17 — “Income Taxes” to our Consolidated Financial Statements in this Form 10-K.
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Restated Quarterly Comparisons
The following table and subsequent section discuss the effect of the restatement for impacted line items on the consolidated statements of operations for the first three quarters in fiscal years 2015 and 2014. Amounts related to derivatives previously classified in accumulated other comprehensive income (loss) have been reclassified to (loss) gain on derivative financial instruments. The total impact to the income statements is shown in “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”
For the Quarter Ended | ||||||||||||||||||||||||
September 30, | December 31, | March 31, | ||||||||||||||||||||||
2014 | 2013 | 2014 | 2013 | 2015 | 2014 | |||||||||||||||||||
(In Thousands, except per share information) (Unaudited) | ||||||||||||||||||||||||
Revenues – Crude oil sales: | ||||||||||||||||||||||||
As previously reported | $ | 368,501 | $ | 289,229 | $ | 324,655 | $ | 262,230 | $ | 232,520 | $ | 249,955 | ||||||||||||
Adjustments to revenues – crude oil sales | 1,654 | 1,737 | (44,947 | ) | 1,397 | (54,915 | ) | 4,686 | ||||||||||||||||
As restated | 370,155 | 290,966 | 279,708 | 263,627 | 177,605 | 254,641 | ||||||||||||||||||
Revenues – natural gas sales: | ||||||||||||||||||||||||
As previously reported | 34,730 | 35,363 | 33,100 | 34,586 | 27,672 | 35,228 | ||||||||||||||||||
Adjustments to revenues – natural gas sales | (169 | ) | (2,779 | ) | (1,299 | ) | (3,448 | ) | (660 | ) | 2,334 | |||||||||||||
As restated | 34,561 | 32,584 | 31,801 | 31,138 | 27,012 | 37,562 | ||||||||||||||||||
(Loss) gain on derivative financial instruments: | ||||||||||||||||||||||||
As previously reported | 3,283 | (1,441 | ) | 886 | (5,722 | ) | (1,932 | ) | 205 | |||||||||||||||
Adjustments to (loss) gain on derivative financial instruments | 53,442 | (28,962 | ) | �� | 190,576 | (15,229 | ) | 18,895 | (7,554 | ) | ||||||||||||||
As restated | 56,725 | (30,403 | ) | 191,462 | (20,951 | ) | 16,963 | (7,349 | ) | |||||||||||||||
Total Revenues: | ||||||||||||||||||||||||
As previously reported | 403,231 | 324,592 | 357,755 | 296,816 | 260,192 | 285,183 | ||||||||||||||||||
Adjustments to total revenues | 58,210 | (31,445 | ) | 145,216 | (23,002 | ) | (38,612 | ) | (329 | ) | ||||||||||||||
As restated | 461,441 | 293,147 | 502,971 | 273,814 | 221,580 | 284,854 | ||||||||||||||||||
Net Income (Loss): | ||||||||||||||||||||||||
As previously reported | (6,403 | ) | 43,139 | (373,879 | ) | 10,495 | (584,317 | ) | 7,292 | |||||||||||||||
Adjustments to net income (loss) | 33,593 | (17,857 | ) | 97,916 | (8,567 | ) | 89,256 | (974 | ) | |||||||||||||||
As restated | 27,190 | 25,282 | (275,963 | ) | 1,928 | (495,061 | ) | 6,318 | ||||||||||||||||
Earnings (Loss) per Share (Basic): | ||||||||||||||||||||||||
As previously reported | (0.10 | ) | 0.53 | (4.01 | ) | 0.10 | (6.22 | ) | 0.06 | |||||||||||||||
Adjustments to earnings (loss) per share (basic) | 0.36 | (0.23 | ) | 1.04 | (0.11 | ) | 0.95 | (0.01 | ) | |||||||||||||||
As restated | 0.26 | 0.30 | (2.97 | ) | (0.01 | ) | (5.27 | ) | 0.05 | |||||||||||||||
Earnings (Loss) per Share (Diluted): | ||||||||||||||||||||||||
As previously reported | (0.10 | ) | 0.51 | (4.01 | ) | 0.10 | (6.22 | ) | 0.06 | |||||||||||||||
Adjustments to earnings (loss) per share (diluted) | 0.34 | (0.24 | ) | 1.04 | (0.11 | ) | 0.95 | (0.01 | ) | |||||||||||||||
As restated | 0.24 | 0.27 | (2.97 | ) | (0.01 | ) | (5.27 | ) | 0.05 |
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Three months ended September 30, 2014 compared with three months ended September 30, 2013
The restatement adjustment increased our consolidated net income available for common stockholders for the three months ended September 30, 2014 by $33.6 million, and decreased our consolidated net income available for common stockholders for the three months ended September 30, 2013 by $17.9 million. Our restated consolidated net income available for common stockholders for the three months ended September 30, 2014 was $24.3 million or $0.24 diluted net income per common share (“per share”) as compared to restated consolidated net income available for common stockholders of $22.4 million or $0.27 per share for the three months ended September 30, 2013. This increase was primarily due to gains on derivative instruments and higher crude oil sales volumes partially offset by lower crude oil sales prices, higher costs and expenses and higher interest expense. See “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”
Revenues
The restatement adjustment increased our consolidated revenues for the three months ended September 30, 2014 by $58.2 million, and decreased our consolidated revenues for the three months ended September 30, 2013 by $31.4 million. Our restated consolidated revenues increased $168.3 million in the first quarter of fiscal 2015 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher oil sales volumes as a result of the EPL Acquisition and gain on derivative financial instruments, partially offset by lower oil sales prices. Average oil prices decreased $10.04 per barrel in the first quarter of fiscal 2015, resulting in lower revenues of $27.5 million. Average natural gas prices increased $0.22 per Mcf during the first quarter of fiscal 2015 resulting in higher revenues of $2.0 million. Our hedging activities more than offset the impact of the decrease in oil prices resulting in higher revenues of $87.1 million or $17.63 per BOE. The gain on derivatives for the quarter ended September 30, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $0.42 per barrel of oil compared to a loss on settlements of $1.06 per barrel of oil for the quarter ended September 30, 2013.
Income Tax Expense
The restatement adjustment increased our income tax expense for the three months ended September 30, 2014 by $23.5 million, and decreased our income tax expense for the three months ended September 30, 2013 by $9.9 million. Restated income tax expense increased by $1.2 million for the three months ended September 30, 2014 compared to the three months ended September 30, 2013. The effective income tax rate for the three months ended September 30, 2014 decreased from the three months ended September 30, 2013 by 0.1%.
Three months ended December 31, 2014 compared with three months ended December 31, 2013
The restatement adjustment increased our consolidated net income available for common stockholders for the three months ended December 31, 2014 by $97.9 million, and decreased our consolidated net income available for common stockholders for the three months ended December 31, 2013 by $8.6 million. Our restated consolidated net loss available for common stockholders for the three months ended December 31, 2014 was $278.8 million or $2.97 diluted net loss per common share as compared to restated consolidated net loss available for common stockholders of $0.9 million or $0.01 per share for the three months ended December 31, 2013. This decrease was primarily due to higher costs and expenses including impairment of goodwill, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes. See “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”
Revenues
The restatement adjustment increased our consolidated revenues for the three months ended December 31, 2014 by $145.2 million, and decreased our consolidated revenues for the three months ended December 31, 2013 by $23.0 million. Our restated consolidated revenues increased $229.2 million in the second quarter of fiscal 2015 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher oil sales volumes as a result of the EPL Acquisition and gain on derivative financial instruments, partially offset by lower commodity sales prices. Average oil prices decreased $22.17 per barrel
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in the second quarter of fiscal 2015, resulting in lower revenues of $61.6 million. Average natural gas prices decreased $0.21 per Mcf during the second quarter of fiscal 2015, resulting in lower revenues of $1.7 million. Our hedging activities more than offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $212.4 million or $40.98 per BOE. The gain on derivatives for the quarter ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $17.95 per barrel of oil compared to a loss on settlements of $0.65 per barrel of oil for the quarter ended December 31, 2013.
Income Tax Expense
The restatement adjustment increased our income tax expense for the three months ended December 31, 2014 by $48.9 million, and decreased our income tax expense for the three months ended December 31, 2013 by $6.5 million. Restated income tax expense increased $36.2 million in the second quarter of fiscal 2015 compared to the second quarter of fiscal 2014. The effective income tax rate (excluding the discrete item from pre-tax book loss) for the second quarter of fiscal 2015 was 43.1% as compared to 68.5% for the second quarter of fiscal 2014. The decrease in the tax rate is primarily due to two elements: (i) the increase in pre-tax net income (excluding discrete items) and (ii) the decrease in common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit.
Six months ended December 31, 2014 compared with six months ended December 31, 2013
The restatement adjustment increased our consolidated net income available for common stockholders for the six months ended December 31, 2014 by $131.5 million, and decreased our consolidated net income available for common stockholders for the six months ended December 31, 2013 by $26.4 million. Our restated consolidated net loss available for common stockholders for the six months ended December 31, 2014 was $254.5 million or $2.71 diluted net loss per share as compared to restated consolidated net income available for common stockholders of $21.5 million or $0.29 per share for the six months ended December 31, 2013. This decrease was primarily due to higher costs and expenses including impairment of goodwill, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes. See “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”
Revenues
The restatement adjustment increased our consolidated revenues for the six months ended December 31, 2014 by $203.4 million, and decreased our consolidated revenues for the six months ended December 31, 2013 by $54.4 million. Our restated consolidated revenues increased $397.5 million in the first six months of fiscal 2015 as compared to the same period in the prior fiscal year. Higher revenues were primarily due to higher oil sales volumes as a result of the EPL Acquisition and gain on derivative financial instruments, partially offset by lower oil sales prices. Average oil prices decreased $16.07 per barrel in the first six months of fiscal 2015, resulting in lower revenues of $88.6 million. Average natural gas prices increased $0.02 per Mcf in the first six months of fiscal 2015, resulting in higher revenues of $0.3 million. Our hedging activities more than offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $299.5 million or $29.25 per BOE. The gain on derivatives for the six months ended December 31, 2014 reflects a gain on settlements and monetization of our derivative contracts of approximately $9.19 per barrel of oil compared to a loss on settlements of $0.85 per barrel of oil for the six months ended December 31, 2013.
Income Tax Expense
The restatement adjustment increased our income tax expense for the six months ended December 31, 2014 by $72.5 million, and decreased our income tax expense for the six months ended December 31, 2013 by $16.4 million. Restated income tax expense increased by $37.4 million in the first six months of fiscal 2015 compared to the first six months of fiscal 2014. The effective income tax rate (excluding the discrete item from pre-tax book loss) for the first six months of fiscal 2015 was 41.5% as compared to 41.9% for the first six months of fiscal 2014. The decrease in the tax rate is primarily due to the decrease in common permanent difference items.
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Three months ended March 31, 2015 compared with three months ended March 31, 2014
The restatement adjustment increased our consolidated net income available for common stockholders for the three months ended March 31, 2015 by $89.3 million, and decreased our consolidated net income available for common stockholders for the three months ended March 31, 2014 by $1.0 million. Our restated consolidated net loss available for common stockholders for the three months ended March 31, 2015 was $497.9 million or $5.27 diluted net loss per common share as compared to restated consolidated net income available for common stockholders of $3.4 million or $0.05 per share for the three months ended March 31, 2014. This decrease was primarily due to higher costs and expenses including impairment of oil and natural gas properties, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes. See “Item 8. Financial Statements and Supplementary Data — Restated Quarterly Financial Statements.”
Revenues
The restatement adjustment decreased our consolidated revenues for the three months ended March 31, 2015 by $38.6 million, and decreased our consolidated revenues for the three months ended March 31, 2014 by $0.3 million. Our restated consolidated revenues decreased $63.3 million in the third quarter of fiscal 2015 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity sales prices partially offset by higher sales volumes as a result of the EPL Acquisition. Average oil prices decreased $52.21 per barrel in the third quarter of fiscal 2015, resulting in lower revenues of $133.4 million. Average natural gas prices decreased $2.27 per Mcf during the third quarter of fiscal 2015, resulting in lower revenues of $17.1 million. Our hedging activities partially offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $24.3 million or $5.07 per BOE. The gain on derivatives for the quarter ended March 31, 2015 reflects a gain on settlements and monetization of our derivative contracts of approximately $29.00 per barrel of oil compared to a loss on settlements of $2.78 per barrel of oil for the quarter ended March 31, 2014.
Costs and Expenses and Other (Income) Expense
The restatement adjustment decreased our costs and expenses for the three months ended March 31, 2015 by $174.5 million, and decreased our costs and expenses for the three months ended March 31, 2014 by $2.0 million. Restated costs and expenses increased $701.8 million in the third quarter of fiscal 2015 as compared to the same period in the prior fiscal year, principally due to the restated impairment of oil and gas properties of $569.6 million.
At the end of each quarter, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to our full cost pool of oil and natural gas properties, net of related deferred taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. As a result of our ceiling test at March 31, 2015, we recognized a restated ceiling test impairment of our oil and natural gas properties totaling $569.6 million. The restatement adjustment decreased our impairment of oil and natural gas properties during the three months ended March 31, 2015 by $170.3 million.
Income Tax Expense
The restatement adjustment increased our income tax expense for the three months ended March 31, 2015 by $46.6 million, and increased our income tax expense for the three months ended March 31, 2014 by $2.6 million. We recorded restated income tax benefit of $290.0 million in the third quarter of fiscal 2015 compared to restated income tax expense of $17.2 million in the third quarter of fiscal 2014. The effective income tax (benefit) rate for the third quarter of fiscal 2015 was (36.9%) as compared to 73.1% for the third quarter of fiscal 2014. The decrease in the tax rate is primarily due to (i) the significant decrease in pre-tax net income and (ii) a decrease in common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit.
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Nine months ended March 31, 2015 compared with nine months ended March 31, 2014
The restatement adjustment increased our consolidated net income available for common stockholders for the nine months ended March 31, 2015 by $220.8 million, and decreased our consolidated net income available for common stockholders for the nine months ended March 31, 2014 by $27.4 million. Our restated consolidated net loss available for common stockholders for the nine months ended March 31, 2015 was $752.4 million or $8.00 diluted net loss per share as compared to restated consolidated net income available for common stockholders of $24.9 million or $0.34 per share for the nine months ended March 31, 2014. This decrease was primarily due to higher costs and expenses including impairment of oil and gas properties, impairment of goodwill, lower oil and natural gas sales prices and higher interest expense partially offset by higher crude oil and natural gas sales volumes.
Revenues
The restatement adjustment increased our consolidated revenues for the nine months ended March 31, 2015 by $164.8 million, and decreased our consolidated revenues for the nine months ended March 31, 2014 by $54.8 million. Our restated consolidated revenues increased $334.2 million in the first nine months of fiscal 2015 as compared to the same period in the prior fiscal year. Lower revenues were primarily due to lower commodity sales prices partially offset by higher sales volumes as a result of the EPL Acquisition. Average oil prices decreased $27.90 per barrel in the first nine months of fiscal 2015, resulting in lower revenues of $225.1 million. Average natural gas prices decreased $0.72 per Mcf during the first nine months of fiscal 2015, resulting in lower revenues of $18.0 million. Our hedging activities more than offset the impact of the decrease in oil and natural gas prices resulting in higher revenues of $323.9 million or $21.25 per BOE. The gain on derivatives for the nine months ended March 31, 2015 reflects a gain on settlements and monetization of our derivative contracts of approximately $15.67 per barrel of oil compared to a loss on settlements of $1.46 per barrel of oil for the nine months ended March 31, 2014.
Costs and Expenses and Other (Income) Expense
The restatement adjustment decreased our costs and expenses for the nine months ended March 31, 2015 by $174.6 million, and decreased our costs and expenses for the nine months ended March 31, 2014 by $14.1 million. Restated costs and expenses increased $1,278.0 million in the first nine months of fiscal 2015 as compared to the same period in the prior fiscal year, principally due to the impairment of oil and gas properties and the impairment of goodwill.
As a result of our ceiling test at March 31, 2015, we recognized a restated ceiling test impairment of our oil and natural gas properties totaling $569.6 million during the nine months ended March 31, 2015. The restatement adjustment decreased our impairment of oil and natural gas properties during the three months ended March 31, 2015 by $170.3 million.
Income Tax Expense
The restatement adjustment increased our income tax expense for the nine months ended March 31, 2015 by $119.1 million, and decreased our income tax expense for the three months ended March 31, 2014 by $13.7 million. We recorded restated income tax benefit of $233.0 million in the first nine months of fiscal 2015 compared to restated income tax expense of $36.8 million in the first nine months of fiscal 2014. The effective income tax (benefit) rate (excluding the discrete item from pre-tax book loss) for the first nine months of fiscal 2015 was (36.0%) as compared to 52.4% for the first nine months of fiscal 2014. The decrease in the tax rate is primarily due to (i) the significant decrease in pre-tax net income and (ii) a decrease in common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit.
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Restated Year Ended June 30, 2014 Compared to the Restated Year Ended June 30, 2013
Our consolidated net income attributable to common stockholders for the year ended June 30, 2014 was $6.6 million or $0.09 diluted income per common share (“per share”) as compared to consolidated net income attributable to common stockholders of $169.3 million or $1.94 diluted income per share for the year ended June 30, 2013. This decrease was primarily due to lower oil sales prices and sales volumes coupled with higher costs and a higher effective income tax rate.
Revenue Variances
Year Ended June 30, | Increase (Decrease) | Percent Increase (Decrease) | ||||||||||||||
2014 (Restated) | 2013 (Restated) | |||||||||||||||
(In thousands) | ||||||||||||||||
Oil | $ | 1,104,208 | $ | 1,067,687 | $ | 36,521 | 3.4 | % | ||||||||
Natural gas | 135,883 | 112,753 | 23,130 | 20.5 | % | |||||||||||
Loss on derivative financial instruments | (86,968 | ) | (21,508 | ) | (65,460 | ) | 304.4 | % | ||||||||
Total Revenues | $ | 1,153,123 | $ | 1,158,932 | $ | (5,809 | ) | (0.5 | )% |
Revenues
Our consolidated revenues decreased $5.8 million in the year ended June 30, 2014 as compared to the year ended June 30, 2013. Lower revenues were primarily due to the loss on derivative financial instruments and lower oil sales prices, partially offset by higher oil sales volumes and higher natural gas sales prices. Revenue variances related to commodity prices and sales volumes are presented in the following table and described below.
Sales Price and Volume Variances
Year Ended June 30, | Increase (Decrease) | Percent Increase (Decrease) | Revenue Increase (Decrease) | |||||||||||||||||
2014 (Restated) | 2013 (Restated) | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||
Price Variance | ||||||||||||||||||||
Oil sales prices (per Bbl)(1) | $ | 100.59 | $ | 103.48 | $ | (2.89 | ) | -2.8 | % | $ | (29,779 | ) | ||||||||
Natural gas sales prices (per Mcf)(1) | 4.15 | 3.48 | 0.67 | 19.3 | % | 21,485 | ||||||||||||||
Loss on derivative financial instruments (per BOE) | (5.29 | ) | (1.37 | ) | (3.92 | ) | 286.1 | % | (65,460 | ) | ||||||||||
Total price variance | (73,754 | ) | ||||||||||||||||||
Volume Variance | ||||||||||||||||||||
Oil sales volumes (MBbls) | 10,978 | 10,318 | 660 | 6.4 | % | 66,300 | ||||||||||||||
Natural gas sales volumes (MMcf) | 32,754 | 32,354 | 400 | 1.2 | % | 1,645 | ||||||||||||||
BOE sales volumes (MBOE) | 16,437 | 15,710 | 727 | 4.6 | % | |||||||||||||||
Percent of BOE from oil | 67 | % | 66 | % | ||||||||||||||||
Total volume variance | 67,945 | |||||||||||||||||||
Total price and volume variance | $ | (5,809 | ) |
(1) | Commodity prices exclude the impact of derivative financial instruments. |
Price Variances
Lower net commodity prices decreased revenues by $8.3 million in the year ended June 30, 2014 as compared to the year ended June 30, 2013. Average oil prices decreased $2.89 per barrel in the year ended June 30, 2014, resulting in decreased revenues of $29.8 million. Average natural gas prices increased $0.67 per Mcf during the year ended June 30, 2014, resulting in increased revenues of $21.5 million. Our hedging activities resulting in lower revenues of $65.5 million or $3.92 per BOE. The loss on derivatives for the year ended June 30, 2014 includes a loss on settlements of our derivative contracts of approximately $1.58 per barrel of oil compared to a loss on settlement of $0.12 per barrel of oil for the year ended June 30, 2013.
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Volume Variances
Oil sales volumes increased 660 MBbls in the year ended June 30, 2014, which resulted in higher revenues of $66.3 million. The increase in oil sales volumes in the year ended June 30, 2014 was primarily due to the results of our capital program and the EPL Acquisition, partially offset by the shut-in of production and natural decline. Natural gas sales volumes increased 400 MMcf in the year ended June 30, 2014, which resulted in improved revenues of $1.6 million. The increase in natural gas sales volumes in the year ended June 30, 2014 was primarily due to the results of our capital program and the EPL Acquisition, partially offset by the shut-in of production and natural decline.
Costs and expenses and other (income) expense
Year Ended June 30, | Increase (Decrease) Total $ | |||||||||||||||||||
2014 (Restated) | 2013 (Restated) | |||||||||||||||||||
Total $ | Per BOE | Total $ | Per BOE | |||||||||||||||||
(In thousands, except per unit amounts) | ||||||||||||||||||||
Cost and expenses | ||||||||||||||||||||
Lease operating expense | ||||||||||||||||||||
Insurance expense | $ | 31,183 | $ | 1.90 | $ | 32,737 | $ | 2.08 | $ | (1,554 | ) | |||||||||
Workover and maintenance | 66,481 | 4.04 | 65,118 | 4.15 | 1,363 | |||||||||||||||
Direct lease operating expense | 268,083 | 16.31 | 239,308 | 15.23 | 28,775 | |||||||||||||||
Total lease operating expense | 365,747 | 22.25 | 337,163 | 21.46 | 28,584 | |||||||||||||||
Production taxes | 5,427 | 0.33 | 5,246 | 0.33 | 181 | |||||||||||||||
Gathering and transportation | 23,532 | 1.43 | 24,168 | 1.54 | (636 | ) | ||||||||||||||
DD&A | 414,026 | 25.19 | 363,791 | 23.16 | 50,235 | |||||||||||||||
Accretion of asset retirement obligations | 30,183 | 1.84 | 30,885 | 1.97 | (702 | ) | ||||||||||||||
General and administrative | 96,402 | 5.87 | 71,598 | 4.56 | 24,804 | |||||||||||||||
Total costs and expenses | $ | 935,317 | $ | 56.91 | $ | 832,851 | $ | 53.02 | $ | 102,466 | ||||||||||
Other (income) expense | ||||||||||||||||||||
(Income) loss from equity method investees | $ | 5,231 | $ | 0.32 | $ | 6,010 | $ | 0.38 | $ | (779 | ) | |||||||||
Other income-net | (3,298 | ) | (0.20 | ) | (1,965 | ) | (0.13 | ) | (1,333 | ) | ||||||||||
Interest expense | 162,728 | 9.90 | 108,659 | 6.92 | 54,069 | |||||||||||||||
Total other (income) expense | $ | 164,661 | $ | 10.02 | $ | 112,704 | $ | 7.17 | $ | 51,957 |
Costs and expenses increased $102.5 million in fiscal 2014 as compared to fiscal 2013. This increase in costs and expenses was due in part to higher production related expenses, higher DD&A expense and higher general and administrative expense in fiscal 2014. Below is a discussion of costs and expenses.
Lease operating expense increased $28.6 million in fiscal 2014 compared to fiscal 2013. This increase was primarily due to higher direct lease operating and workover and maintenance expenses stemming from the increase in producing properties resulting from acquisitions and from our capital program.
DD&A expense increased $50.2 million due to a higher DD&A rate ($31.9 million) and higher equivalent production ($18.3 million) in fiscal 2014 as compared to fiscal 2013.
General and administrative expense increased $24.8 million in fiscal 2014 as compared to fiscal 2013, principally as a result of approximately $13.6 million in one-time costs associated with the EPL Acquisition and higher employee related costs of approximately $11.2 million due to an increase in the number of employees in fiscal year 2014.
Other (income) expense increased $52.0 million in fiscal 2014 as compared to fiscal 2013, principally due to higher interest expense due to increased borrowings.
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Income Tax Expense
Income tax expense increased $2.4 million in fiscal 2014 compared to fiscal 2013. The effective income tax rate increased to 65.9% for fiscal 2014 from 15.3% for fiscal 2013. This increase was due to: (i) the tax effect of the release of a $7.8 million valuation allowance in fiscal year 2013, which did not occur in fiscal year 2014, (ii) to the disallowance (for tax purposes) of certain transaction costs related to the EPL Acquisition, among other customary permanent differences during fiscal year 2014, and (iii) lower pre-tax income in fiscal 2014 than 2013.
Proved Reserves
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. 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.
Year Ended June 30, 2015 | Year Ended June 30, 2014 | |||||||||||||||||||||||
Oil MMBbls | Natural Gas Bcf | MMBOE | Oil MMBbls | Natural Gas Bcf | MMBOE | |||||||||||||||||||
Proved | ||||||||||||||||||||||||
Developed | 94.0 | 188.0 | 125.3 | 112.8 | 222.9 | 149.9 | ||||||||||||||||||
Undeveloped | 43.1 | 90.5 | 58.2 | 72.6 | 142.0 | 96.3 | ||||||||||||||||||
Total Proved | 137.1 | 278.5 | 183.5 | 185.4 | 364.9 | 246.2 |
Our proved developed reserve estimates decreased by 24.6 MMBOE or 16% to 125.3 MMBOE at June 30, 2015 from 149.9 MMBOE at June 30, 2014. The decrease was primarily due to:
• | Downward revision of 12.8 MMBOE, primarily due to the effect of reduced oil and gas prices, |
• | Divestiture of 11.7 MMBOE, and |
• | Production of 21.5 MMBOE. |
Offset by:
• | Additions of 8.5 MMBOE primarily from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from six fields: South Pass 78, Lomond North, West Delta 73, Main Pass 61, South Timbalier 54 and South Pass 49, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Our proved undeveloped reserve estimates decreased by 38.1 MMBOE or 40% to 58.2 MMBOE at June 30, 2015 from 96.3 MMBOE at June 30, 2014. The decrease was primarily due to:
• | Downward revisions of 33.6 MMBOE comprised of (i) 7.3 MMBOE due to the effect of reduced oil and gas prices, (ii) 7.0 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 19.3 MMBOE due to new data and field studies. Of the 19.3 MMBOE of downward revisions due to new data and field studies, more than 80% occurred in seven fields: Grand Isle 16, Ship Shoal 208, South Timbalier 21, South Timbalier 26, Vermilion 164, West Delta 30 and West Delta 73, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Offset by:
• | Additions of 8.8 MMBOE, primarily due to additional drilling locations to make up for the lower throughput per well in West Delta 73, a replacement location at Bayou Carlin, and from the identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 73. |
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In the fiscal year ended June 30, 2015, we developed approximately 13.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 21 gross, 21 net wells at a net cost of approximately $237 million.
We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including top value projects, maximization of present value and production volumes, drilling obligations, five-year rule requirements, and anticipated availability of certain rig types. The relative portion of total PUD reserves that we develop over the next five years will not be uniform from year to year, but will vary by year depending on several factors; including financial targets such as reducing debt and/or drilling within cash flow, drilling obligatory wells and the inclusion of newly acquired proved undeveloped reserves. As scheduled in our long range plan, all of our PUD locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report, with the exception of four locations totaling 3,560 MBOE or 6.1% of our PUD reserves. These four locations are to be sidetracked from existing wellbores which are still producing economically, thus cannot be drilled until the proved developed producing zones deplete.
Although the schedule for development of our PUDs has historically changed based on external factors such as changes in commodity prices, the availability of capital, acquisitions, regulatory matters and the availability of drilling rigs that are capable of drilling in the given area, and our current PUD schedule is also subject to change due to external factors, we believe our PUDs will be converted in a timely manner given our enhanced focus on development drilling in our long range plan and current availability of capital to execute that plan. Senior management continuously monitors our development drilling plan to ensure that there is reasonable certainty of proceeding with our development plans and is required to approve any changes made to the existing long range plan and the related development plan.
Liquidity and Capital Resources
Overview
We have historically funded our operations primarily through cash flows from operations, borrowings under our revolving credit facility, and proceeds from the issuance of debt and equity securities. However, future cash flows are subject to a number of variables, including the level of crude oil and natural gas production and prices. Oil prices declined severely during the second quarter of our fiscal year 2015, with continued lower prices throughout the second half of fiscal year 2015. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position.
We recently have taken several actions to improve our liquidity position. On March 12, 2015, we closed our private placement of $1.45 billion in aggregate principal amount of the 11.0% Notes, as described below, for net proceeds of $1.35 billion, after deducting the initial purchasers’ discount and direct offering costs paid by us. Of the net proceeds $836 million was used to reduce our then outstanding borrowings on our revolving credit facility to $150 million, with the remaining amount available for general corporate purposes, including funding a portion of our capital expenditure program for fiscal year 2015. In connection with the issuance of the 11.0% Notes, we proactively amended our revolving credit facility, to, among other things, reduce the total borrowing base availability to $500 million and make certain modifications to the existing financial covenants.
On June 30, 2015, we sold the Grand Isle Gathering System for $245 million in cash, plus the assumption of an estimated $12.5 million asset retirement obligation associated with the decommissioning costs of the Grand Isle Gathering System. In connection with the closing of the sale of the Grand Isle Gathering System, we entered into a triple-net lease with Grand Isle Corridor pursuant to which we will continue to operate the Grand Isle Gathering System. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the Grand Isle Gathering System above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum monthly payments for
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the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease.
In addition, on June 30, 2015, we sold our interest in the East Bay field for cash consideration of $21 million, plus the assumption of asset retirement obligations totaling approximately $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field.
As a result of these measures, as of June 30, 2015, we had approximately $124 million of available borrowing capacity under our revolving credit facility, which has a borrowing base of $500 million, and cash and cash equivalents of approximately $773 million, for total liquidity of $897 million. We had approximately $150 million in borrowings and $226 million in letters of credit issued under the facility.
However, we also have substantial indebtedness. As of June 30, 2015, we had total indebtedness of $4,608 million as described in greater detail under “— Our Indebtedness and Available Credit.” From July through September 2015, we repurchased approximately $253.7 million, $50.4 million and $123.7 million in aggregate principal amount of the 7.5% Senior Notes, the 6.875% Senior Notes, and the 7.75% Senior Notes respectively, in open market transactions at a total price of approximately $94.4 million. As a result, we had total indebtedness of $4,185 million as of September 22, 2015. All of our outstanding indebtedness will mature within the next ten years, with a substantial portion coming due in the next five years. The maturity dates for our outstanding notes are as follows (debt amounts as of September 22, 2015, reflecting note repurchases completed by the Company subsequent to June 30, 2015):
• | 9.25% Senior Notes due December 15, 2017 ($750 million) |
• | 8.25% Senior Notes due February 15, 2018 ($510 million) |
• | 3.0% Convertible Notes due December 15, 2018 ($400 million) |
• | 7.75% Senior Notes due June 15, 2019 ($126.3 million) |
• | 11.0% Senior Secured Second Lien Notes due March 15, 2020 ($1.45 billion) |
• | 7.50% Senior Notes due December 15, 2021 ($246.3 million) |
• | 6.875% Senior Notes due March 15, 2024 ($599.6 million) |
In addition, the maturity of certain of our outstanding indebtedness may be accelerated in certain situations. Pursuant to the indenture governing our 11.0% Notes, we will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes (December 15, 2017), if on such date the aggregate outstanding principal amount of all such notes exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes (February 15, 2018), if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes exceeds $250.0 million. In addition, our revolving credit facility is scheduled to mature on April 9, 2018; however, the maturity of our revolving credit facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017.
Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon oil and natural gas prices, the success of our development activities, our ability to maintain and grow reserves and our ability to refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by the results of our operations, economic and capital market conditions, oil and natural gas prices and other factors, many of which are beyond our control. For example, constraints in the credit markets may increase the rates we are charged for utilizing these markets. If we are unable to generate sufficient cash flow to service our debt or meet our debt obligations as they become due, we will
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have to take certain actions described in greater detail in “Risk Factors — We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions in order to satisfy our obligations under our indebtedness, which may not be successful.” Currently, we believe that our liquidity and capital resource alternatives available to us will be adequate to meet our funding requirements at least through June 30, 2016.
Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement at least through June 30, 2016; however, commodity prices have been extremely volatile in recent history and a protracted further decline in commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods. A breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. Certain payment defaults or acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.
In light of current commodity prices and our substantial leverage position, we continue to analyze a variety of transactions and mechanisms designed to reduce debt, including the retirement or purchase of outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise and opportunistic acquisitions. Such transactions, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors and there can be no assurance that we will take any of these actions.
Our Indebtedness and Available Credit
Revolving Credit Facility. During March 2015, the Tenth Amendment to the First Lien Credit Agreement dated as of March 3, 2015 (the “Tenth Amendment”) became effective. Pursuant to the terms of the Tenth Amendment, the lenders under the First Lien Credit Agreement reduced the borrowing base from $1,500 million to $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement. As of June 30, 2015, we had $150.0 million in borrowings and $226.0 million in letters of credit issued under our First Lien Credit Agreement. The maturity date of the First Lien Credit Agreement is April 9, 2018, provided that certain conditions are met; however, the maturity of our revolving credit facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by May 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by July 15, 2017. Our revolving credit facility is comprised of a syndicate of large domestic and international banks, with no single lender providing more than 5% of the overall commitment amount.
Additionally, as of July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver to the First Lien Credit Agreement (the “Eleventh Amendment”), which waives certain provisions of the First Lien Credit Agreement to permit the M21K acquisition described above as well as an additional minor acquisition and the disposition of the East Cameron pipeline. Further, the Eleventh Amendment temporarily increased the letter of credit commitment amount within the facility from $300 million to a maximum amount of $305 million through August 31, 2015, after which it reduced back to $300 million. Please see Note 21 — “Subsequent Events” to our Consolidated Financial Statements in this Form 10-K.
The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenant on a consolidated basis: a minimum current ratio of no less than 1.0 to 1.0. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If the EPL Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a
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consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the revolving credit facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.
As of June 30, 2015, we were in compliance with all covenants under the First Lien Credit Agreement, other than with respect to the sale of interests in the East Bay field. Since required lender consent to the specific terms of the transaction had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required EPL to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC. We expect to remain in compliance with the financial covenants thereunder for at least the twelve months following the filing date of this Form 10-K.
As a result of the reduction in our borrowing base availability to $500 million and the resulting increased asset coverage for the revolving credit facility, we do not currently anticipate any further borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, our borrowing base under our revolving credit facility may be further reduced which would impact the working capital available to fund our capital spending program. In addition, we would have to repay any outstanding indebtedness in excess of any reduced borrowing base.
11.0% Notes. On March 12, 2015, EGC issued $1.45 billion in aggregate principal amount of the 11.0% Notes, which are senior secured second lien notes due March 15, 2020. The offering of the 11.0% Notes resulted in net proceeds of approximately $1.35 billion after deducting the original issue discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.0%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. As such, the 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. EGC incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the 11.0% Notes. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the original issue discount of $53.5 million as well as the direct offering costs.
The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the guarantors and U.S. Bank National Association, as trustee. The 11.0% Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC, in each case to the extent such assets secure our revolving credit facility. In the future, the 11.0% Notes may be guaranteed by certain of EGC’s material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our revolving credit facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.
On or after September 15, 2017, EGC will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate
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principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, EGC may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30 th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require EGC to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.
8.25% Senior Notes. On June 3, 2014, EGC assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.
6.875% Senior Notes. On May 27, 2014, EGC issued the 6.875% Senior Notes which consisted of $650 million in aggregate principal amount due March 15, 2024. On November 25, 2014, we filed a registration statement with the SEC for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. On May 1, 2015, we filed Amendment No. 1 to the registration statement and the registration statement was declared effective by the SEC. The exchange offer commenced on May 4, 2015, and we completed the exchange offer on June 1, 2015. On or after March 15, 2019, EGC will have the right to redeem all or a portion of the 6.875% Senior Notes at redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.
3.0% Senior Convertible Notes. On November 18, 2013, Energy XXI Ltd, our ultimate parent company (the “Parent”) sold $400 million face value of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of the Parent, based on an initial conversion rate of 24.7523 shares of common
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stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
7.5% Senior Notes. On September 26, 2013, EGC issued at par $500 million in aggregate principal amount of 7.5% unsecured senior notes due December 15, 2021 (the “7.5% Senior Notes”). In April 2014, we filed Amendment No. 1 to the registration statement with the SEC for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. On or after December 15, 2016, EGC will have the right to redeem all or a portion of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.
7.75% Senior Notes. On February 25, 2011, EGC issued at par $250 million in aggregate principal amount of 7.75% unsecured senior notes due June 15, 2019 (the “7.75% Old Senior Notes”). On July 7, 2011, the full $250 million aggregate principal amount of the 7.75% Old Senior Notes was exchanged for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”). The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes. The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.
9.25% Senior Notes. On December 17, 2010, EGC issued at par $750 million in aggregate principal amount of 9.25% unsecured senior notes due December 15, 2017 (the “9.25% Old Senior Notes”). On July 8, 2011, $749 million aggregate principal amount of the 9.25% Old Senior Notes were exchanged for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million aggregate principal amount of the 9.25% Old Senior Notes were lifted on December 17, 2011. The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.
4.14% Promissory Note. In September 2012, we entered into a promissory note of $5.5 million to acquire certain other property and equipment. The terms of this note require us to make monthly payments of approximately $52,000 and a lump-sum payment of $3.3 million at maturity in October 2017. This note carries an interest rate of 4.14% per annum.
For more information regarding our outstanding indebtedness, see Note 7 — “Long Term Debt” of Notes to our Consolidated Financial Statements in this Form 10-K.
BOEM Bonding Requirements
As a lessee and operator of oil and natural gas leases on the federal OCS, we currently maintain approximately $218.0 million in lease and/or area bonds issued to the BOEM and approximately $161.7 million in bonds issued to predecessor third party assignors including certain state regulatory bodies of certain wells and facilities on leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. Thus, our
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total supplemental bonding is approximately $379.7 million, with an annual premium expense of $5.9 million, and approximately $12 million in collateral posted. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM (which is reflected in the $157.6 million in lease and/or area bonds discussed above), and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.
The BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations; re-evaluate the adequacy of our financial assurances; and require us to provide additional supplemental bonding or other surety for most or all of our properties. We also maintain $226 million in letters of credit to third parties on additional assets in the Gulf of Mexico. With respect to our existing bonds and letters of credit with third parties, we can provide no assurance that the BOEM will consider them when determining the total value of additional financial assurances and/or bonding we must provide. In addition, since June 2015, we have received additional letters from the BOEM in which the BOEM requests additional supplemental bonding for other certain properties previously exempt from supplemental bonding. Furthermore, we anticipate our supplemental bonding requirements to increase as we further develop or acquire additional properties subject to the BOEM’s financial assurance requirements. The cost of compliance with any changes in our supplemental bonding requirements could be substantial and could materially and adversely affect our financial condition, cash flows, and results of operations. In addition, we may be required to provide letters of credit to support the issuance of such bonds or other surety. Such letters of credit would likely be issued under our credit facility and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our credit facility to support such supplemental bonding requirements.
Potential Divestitures
We may decide to divest of certain non-core assets from time to time. There can be no assurance any such potential transactions will prove successful. We cannot provide any assurance that we will be able to sell these assets on satisfactory terms, if at all.
Capital Expenditures
For fiscal 2015, we incurred capital costs of approximately $649 million, of which approximately $503 million was spent on development of our core properties, $38 million on exploration of core properties and $108 million on other assets. Our initial fiscal year 2016 capital budget, excluding any potential acquisitions, is expected to be approximately $130 million to $150 million. Approximately 41% of our 2016 capital budget is expected to be focused on development of our core properties and the remainder on other assets. We intend to fund our capital expenditure program and contractual commitments, including settlement of derivative contracts, from cash on hand, cash flows from operations, and borrowings under our revolving credit facility. If oil and natural gas prices remain at current levels or continue to decline, we may be required to reduce our capital expenditure budget for fiscal year 2016 and future years, which in turn may affect our liquidity and results of operations in future periods. If our cash on hand, cash flows from operations and availability under our revolving credit facility are not sufficient to fund our capital program, we may further reduce our capital spending or otherwise fund our capital needs with proceeds from additional debt and equity or the sale of non-core assets. There is no guarantee that we can access debt and equity capital markets or sell non-core assets at attractive terms. Our capital expenditures and the scope of our drilling activities for fiscal year 2016 may change as a result of several factors, including, but not limited to, changes in oil and natural gas sales prices, costs of drilling and completion operations and drilling results.
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Cash Flows
The following table sets forth selected historical information from our statement of cash flows:
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
(In thousands) | ||||||||||||
Net cash provided by operating activities | $ | 330,753 | $ | 545,460 | $ | 638,148 | ||||||
Net cash used in investing activities | (460,448 | ) | (1,544,575 | ) | (994,003 | ) | ||||||
Net cash provided by financing activities | 740,737 | 1,144,921 | 238,768 | |||||||||
Net increase (decrease) in cash and cash equivalents | $ | 611,042 | $ | 145,806 | $ | (117,087 | ) |
Operating Activities. Net cash provided by operating activities for the fiscal year 2015 was $330.8 million as compared to $545.5 million for the fiscal year 2014. The decrease was due in part to lower oil and natural gas prices and higher production costs, partially offset by higher production volumes and proceeds from sale of derivative instruments. Changes in operating assets and liabilities contributed $76.6 million to the decrease in operating cash flow during fiscal 2015, primarily due to changes in accounts payable and accrued liabilities.
Generally, producing natural gas and crude oil reservoirs have declining production rates. Production rates are impacted by numerous factors, including but not limited to, geological, geophysical and engineering matters, production curtailments and restrictions, weather, market demands and our ability to replace depleting reserves. Our inability to adequately replace reserves could result in a decline in production volumes, one of the key drivers of generating net operating cash flows.
Investing Activities. For the fiscal years 2015 and 2014, our cash used for capital expenditures and acquisitions totaled $724.1 million and $1,638.3 million, respectively. The decrease in net cash used in investing activities in fiscal year 2015 compared to fiscal year 2014 was primarily due to the EPL Acquisition in fiscal 2014, an increase in proceeds from the sale of properties, primarily the GIGS, and a reduction in capital expenditures combined with distributions from equity investees.
Financing Activities. Cash provided by financing activities was $761.7 million for fiscal year 2015 as compared to $1,144.9 million for fiscal year 2014. During the year ended June 30, 2015, financing activities include net proceeds of $1.35 billion from the issuance of the 11.0% Notes (after payment of $41.7 million of debt issuance costs) and net repayments on our revolving credit facility of $539.0 million. During the year ended June 30, 2014, net proceeds from our long-term borrowings were $1,341.4 million and purchases of our common shares under our share repurchase program were $184.3 million.
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Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2015, we are obligated to make under our contractual obligations and commitments, other than hedging contracts. We expect to fund these contractual obligations with cash on hand, cash generated from operations and borrowings available under our revolving credit facility.
Payments Due by Period | ||||||||||||||||||||
Total | Less than 1 Year | 1 – 3 Years | 4 – 5 Years | After 5 Years | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Contractual Obligations | ||||||||||||||||||||
Total long-term debt(1) | $ | 4,675,859 | $ | 11,395 | $ | 1,443,923 | $ | 2,070,541 | $ | 1,150,000 | ||||||||||
Interest on long-term debt(1) | 1,707,008 | 399,074 | 669,845 | 455,185 | 182,904 | |||||||||||||||
Operating leases(2) | 478,264 | 35,978 | 76,476 | 81,277 | 284,533 | |||||||||||||||
Drilling rig commitments(2) | 11,547 | 11,547 | — | — | — | |||||||||||||||
Total contractual obligations | 6,872,678 | 457,994 | 2,190,244 | 2,607,003 | 1,617,437 | |||||||||||||||
Other Obligations | ||||||||||||||||||||
Asset retirement obligations(3) | 487,085 | 36,314 | 88,172 | 41,188 | 321,411 | |||||||||||||||
Performance bond premiums(4) | 23,600 | 4,720 | 9,440 | 9,440 | — | |||||||||||||||
Total obligations | $ | 7,359,763 | $ | 494,308 | $ | 2,278,416 | $ | 2,648,191 | $ | 1,938,848 |
(1) | See Note 7 — “Long-Term Debt” to our Consolidated Financial Statements in this Form 10-K for details of our long-term debt. |
(2) | See Note 16 — “Commitments and Contingencies” to our Consolidated Financial Statements in this Form 10-K for discussion of these commitments. |
(3) | See Note 9 — “Asset Retirement Obligations” to our Consolidated Financial Statements in this Form 10-K for details of asset retirement obligations. The obligations reflected above are discounted. In addition, the table above does not include performance bonds totaling $319.2 million and letters of credit of $226 million which support our asset retirement obligations. |
(4) | See Note 16 — “Commitments and Contingencies” to our Consolidated Financial Statements in this Form 10-K. As of June 30, 2015, our total annual premium expense for supplemental bonding totaled $4.7 million, which excludes the additional annual performance bond premium expense of approximately $1.2 million in connection with the acquisition of the equity interest in M21K in August 2015 as described in Note 21 — “Subsequent Events” to our Consolidated Financial Statements in this Form 10-K. The BOEM may in the future continue to review our plugging, abandonment, decommissioning and removal obligations, re-evaluate the adequacy of our financial assurances, and require us to provide additional supplemental bonding or other surety for most or all of our properties. |
Off-Balance Sheet Arrangements
We may enter into off-balance sheet transactions which may give rise to material off-balance sheet liabilities. As of June 30, 2015, the material off-balance sheet transactions entered into by us include operating lease agreements and drilling rig contracts. See contractual obligations table above. In addition, as of June 30, 2015, we had provided a guarantee related to the payment of asset retirement obligations and other liabilities of M21K, and our equity method investee, EXXI M21K, was a guarantor of a $100 million first lien credit facility agreement entered into by M21K, which had a $40 million borrowing base and under which $28.0 million in loans and $1.2 million in letters of credit were outstanding as of June 30, 2015. See Note 6 — “Equity Method Investments”, Note 14 — “Related Party Transactions” and Note 21 — “Subsequent Events” to our Consolidated Financial Statements in this Form 10-K for more information.
Other than the off-balance sheet transactions listed above, we have no other transactions, arrangements or relationships with other persons that are reasonably likely to materially affect our liquidity or availability of capital resources.
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Critical Accounting Policies
We have identified the following policies as critical to the understanding of our financial condition and results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for management’s judgment in selecting their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of our financial condition and results of operations and require management’s most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. Our critical accounting policies and estimates are set forth below. Certain of these accounting policies and estimates are particularly sensitive because of their complexity and the possibility that future events affecting them may differ materially from our management’s current judgment. Our most sensitive estimate affecting our financial statements are our oil and gas reserves, which are highly sensitive to changes in oil and gas prices that have been volatile in recent years. Although decreases in oil and gas prices are partially offset by our hedging program, to the extent reserves are adversely impacted by reductions in oil and gas prices, we could experience increased depreciation, depletion and amortization expense and full cost ceiling impairments in future periods.
Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
Proved Oil and Gas Reserves. Proved oil and gas reserves are currently defined by the SEC as those volumes of oil and gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered from existing wells with existing equipment and operating methods. Although our internal and external engineers are knowledgeable of and follow the guidelines for reserves established by the SEC, the estimation of reserves requires the engineers to make a number of assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions in reserve quantities. Reserve revisions will inherently lead to adjustments of DD&A rates. We cannot predict the types of reserve revisions that will be required in future periods.
Oil and Natural Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.
Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include
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non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated or over the life of the reservoir.
We evaluate the impairment of our evaluated oil and gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capital costs. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves. Oil and gas reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.
Business Combinations. For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax basis of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of oil and natural gas reserves. We estimate future prices to apply to the estimated reserve quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
Estimated deferred taxes are based on available information concerning the tax bases of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 with the EPL Acquisition and was recorded to our oil and gas reporting unit.
At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.
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Asset Retirement Obligations. Our investment in oil and gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties cost that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors that are difficult to predict.
Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We previously designated the majority of our derivative instruments as cash flow hedges, however, in connection with preparing our Form 10-K for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges related to our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, our currently outstanding derivative contracts are not accounted for as cash flow hedges. Therefore, changes in fair value of these outstanding derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations.
Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. Changes in the financial accounting method for derivative instruments caused no changes in previous tax filings or deferred tax balances related to these instruments. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.
When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. In light of changes in our expectations regarding our future taxable income, consistent with the results of operations for the current year (heavily affected by impairments), we recorded an increase in our valuation allowance of $356.8 million resulting in a balance of $365.0 million at June 30, 2015. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana net operating loss (NOL) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax at 30% is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.
Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.
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Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). Early adoption is permitted for annual periods beginning after December 15, 2016, and interim periods therein. We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15,Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03,Interest — Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it will have on our consolidated financial position and footnote disclosures.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
General
We are exposed to a variety of market risks including commodity price risk and interest rate risk. We address these risks through a program of risk management which includes the use of derivative instruments. The following quantitative and qualitative information is provided about financial instruments to which we were a party at June 30, 2015, and from which we may incur future gains or losses from changes in market interest rates or commodity prices. We do not enter into derivative or other financial instruments for speculative or trading purposes.
Hypothetical changes in commodity prices and interest rates chosen for the following estimated sensitivity analysis are considered to be reasonably possible near-term changes generally based on consideration of past fluctuations for each risk category. However, since it is not possible to accurately predict future changes in interest rates and commodity prices, these hypothetical changes may not necessarily be an indicator of probable future fluctuations.
Commodity Price Risk
Our major market risk exposure continues to be the pricing applicable to our oil and natural gas production. Our revenues, profitability and future rate of growth depend substantially upon the market prices of oil and natural gas, which are volatile and may fluctuate widely. Oil and natural gas price declines such as the recent declines adversely affect our revenues, cash flows and profitability.
Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. We have incurred debt under the borrowing base of our revolving credit facility. This borrowing base is subject to periodic redetermination based in part on changing expectations of future prices. Recently, commodity prices have deteriorated materially. As a result of the reduction in our borrowing base
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availability to $500 million and the resulting increased asset coverage for the revolving credit facility, we do not currently anticipate any further borrowing base reductions in connection with our semi-annual borrowing base redeterminations. However, it is possible if commodity prices were to decline significantly from current levels, our borrowing base under our revolving credit facility may be further reduced which would require us to repay that portion, if any, of our outstanding indebtedness under the facility in excess of the new borrowing base. The energy markets have historically been very volatile, and there can be no assurance that crude oil and natural gas prices will improve.
We utilize commodity-based derivative instruments with major financial institutions to reduce exposure to fluctuations in the price of crude oil and natural gas. We also use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Any gains or losses resulting from the change in fair value from hedging transactions and from the settlement of hedging contracts are recorded in earnings as a component of revenues.
With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.
As of June 30, 2015, we had the following net open crude oil derivative positions:
Weighted Average Contract Price | ||||||||||||||||||||||||
Collars/Put | ||||||||||||||||||||||||
Remaining Contract Term | Type of Contract | Index | Volumes (MBbls) | Sub Floor | Floor | Ceiling | ||||||||||||||||||
July 2015 – December 2015 | Three-Way Collars | ARGUS-LLS | 3,680 | $ | 32.50 | $ | 45.00 | $ | 75.00 | |||||||||||||||
July 2015 – December 2015 | Collars | ARGUS-LLS | 920 | 80.00 | 123.38 | |||||||||||||||||||
July 2015 – December 2015 | Collars | NYMEX-WTI | 276 | 75.00 | 85.00 | |||||||||||||||||||
July 2015 – December 2015 | Bought Put | NYMEX-WTI | 552 | 90.00 | ||||||||||||||||||||
July 2015 – December 2015 | Sold Put | NYMEX-WTI | (552 | ) | 90.00 | |||||||||||||||||||
January 2016 – June 2016 | Collars | NYMEX-WTI | 2,548 | 51.43 | 74.70 | |||||||||||||||||||
July 2016 – December 2016 | Collars | NYMEX-WTI | 2,576 | 51.43 | 74.70 |
As of June 30, 2015, we had the following net open natural gas derivative position:
Remaining Contract Term | Type of Contract | Index | Volumes (MMBtu) | Swaps Fixed Price | ||||||||||||
July 2015 – December 2015 | Swaps | NYMEX-HH | 791 | $ | 4.31 |
At June 30, 2015, our crude oil contracts outstanding were in an asset position of $21.2 million. A 10% increase in crude oil prices would reduce the fair value by approximately $30.0 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $24.8 million. Also at June 30, 2015, our natural gas contract outstanding was in an asset position of $0.9 million. A 10% increase in natural gas prices would reduce the fair value by approximately $0.2 million, while a 10% decrease in natural gas prices would
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increase the fair value by approximately $0.2 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2015.
Our ultimate realized gain or loss with respect to commodity price fluctuations will depend on the future exposures that arise during the period, our hedging strategies at the time and commodity prices at the time.
For a complete discussion of our open commodity derivatives as of June 30, 2015, please see Note 10 — “Derivative Financial Instruments” to our Consolidated Financial Statements in this Form 10-K.
Interest Rate Risk
Our exposure to changes in interest rates relates primarily to our variable rate debt obligations. Specifically, we are exposed to changes in interest rates as a result of borrowings under our revolving credit facility, and the terms of such facility require us to pay higher interest rate margins as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by limiting our variable-rate debt to a certain percentage of total capitalization and by monitoring the effects of market changes in interest rates. We consider our interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 96.7% of our debt. As of June 30, 2015, total debt included $150 million of floating-rate debt. As a result, our period-end interest costs will fluctuate based on short-term interest rates on approximately 3.3% of our total debt outstanding as of June 30, 2015. A 10% change in floating interest rates on period-end floating debt balances would change annual interest expense by approximately $28,125. We currently have no interest rate hedge positions in place to reduce our exposure to changes in interest rates. However, to reduce our future exposure to changes in interest rates, we may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to existing debt issues.
We generally invest cash equivalents in high-quality credit instruments consisting primarily of money market funds with maturities of 90 days or less. We do not expect any material loss from cash equivalents and therefore we believe our interest rate exposure on invested funds is not material.
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Item 8. Financial Statements and Supplementary Data
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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed by management, under the supervision of our principal executive and principal financial officers, and effected by our Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the U.S. (“U.S. GAAP”) and includes those policies and procedures that:
• | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
• | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and |
• | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management, under the supervision and participation of our principal executive officer and our principal financial officer, assessed the effectiveness of our internal control over financial reporting as of June 30, 2015. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) inInternal Control-Integrated Framework (2013).
Prior to the issuance of this Form 10-K, management determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815, Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, we restated our consolidated balance sheet as of June 30, 2014, our consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended June 30, 2014 and 2013, and restated quarterly financial information for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, March 31, 2015 and 2014, and June 30, 2014.
Management evaluated the impact of this restatement on our assessment of our internal control over financial reporting. Management has concluded that the controls in place relating to the documentation of hedge designations were not properly designed to provide reasonable assurance that these derivative contracts would be properly recorded and disclosed in the financial statements in accordance with U.S. GAAP; and, that this represents a material weakness in our internal control over financial reporting as of June 30, 2015. As a result of the assessment performed and the material weakness noted, management has concluded that our internal control over financial reporting was not effective as of June 30, 2015. Further, we have determined that these control deficiencies existed with respect to certain aspects of our historical financial reporting and, accordingly, we have concluded that our prior disclosures regarding the sufficiency of our disclosure controls, internal controls and changes in internal controls may not have been correct.
In addition, the Board has recently learned that, in 2007, 2009 and 2014, the Company’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provided the Company with services. The Board also learned that Norman Louie, one of our directors, made a personal loan to Mr. Schiller in 2014 before Mr. Louie became a director of the Company. At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of
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June 30, 2015, owned a majority interest in Energy XXI M21K and 6.3% of the Company’s common stock. The loans made in 2014 are still outstanding. Since Mr. Schiller did not disclose the personal loans before they were made, the Board has determined that he did not comply with the procedural requirements of the Company’s Code of Business Conduct and Ethics. Upon learning of Mr. Schiller’s personal loans from affiliates of service providers, the Board engaged independent legal counsel to conduct an internal investigation, with the assistance of outside forensic accountants, to review these loans and the Company’s vendor procurement processes. The Board is still reviewing the results of the internal investigation. Although the internal investigation has not uncovered any illegal activity or any impact on the Company’s financial reporting or financial statements, the Company concluded this non-compliance to be a material weakness in its control environment given the leadership position of this officer, the visibility and importance of his actions to the Company’s overall system of controls and the significance with which the Company views this nondisclosure. As part of its review, the Board has begun the process of designing and implementing additional controls and procedures, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise from Mr. Schiller’s personal loans; revising the Code of Business Conduct and Ethics to explicitly ban any such personal loans in the future; and implementing an enhanced comprehensive training program on the Company’s Code of Business Conduct and Ethics.
BDO USA, LLP, the independent registered public accounting firm that audited the consolidated financial statements included in this Form 10-K, has issued a report on our internal control over financial reporting as of June 30, 2015. This report, dated September 29, 2015, appears on the following page.
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Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Energy XXI Ltd
Houston, Texas
We have audited Energy XXI Ltd and subsidiaries’ (the “Company”) internal control over financial reporting as of June 30, 2015, based on criteria established inInternal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Energy XXI Ltd and subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 8, Management’s Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses were noted: (i) management failed to design and maintain controls over the documentation of hedge designations to provide reasonable assurance that derivative contracts would be properly recorded and disclosed in the consolidated financial statements and (ii) the Company’s Chief Executive Officer failed to disclose certain potential conflicts of interests which, given his leadership position and the visibility and importance of his actions to the Company’s overall system of controls, is considered a material weakness in the Company’s control environment. These material weaknesses have been identified and described in management’s assessment. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2015 consolidated financial statements, and this report does not affect our report dated September 29, 2015 on those consolidated financial statements.
In our opinion, Energy XXI Ltd and subsidiaries did not maintain, in all material respects, effective internal control over financial reporting as of June 30, 2015, based on the COSO criteria.
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We do not express an opinion or any other form of assurance on management’s statements referring to the results of the internal investigation or to any corrective actions taken by the Company after the date of management’s assessment.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Energy XXI Ltd and subsidiaries as of June 30, 2015, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year then ended and our report dated September 29, 2015 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
September 29, 2015
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Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Energy XXI Ltd
Houston, Texas
We have audited the accompanying consolidated balance sheet of Energy XXI Ltd and subsidiaries (the “Company”) as of June 30, 2015 and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we have also audited the financial statement schedule listed in Item 15(a)(2) as of and for the year ended June 30, 2015. Our responsibility is to express an opinion on these consolidated financial statements and schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements and schedule. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy XXI Ltd and subsidiaries at June 30, 2015, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
Also in our opinion, the related financial statement schedule as of and for the year ended June 30, 2015, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Energy XXI Ltd and subsidiaries’ internal control over financial reporting as of June 30, 2015, based on criteria established inInternal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 29, 2015 expressed an adverse opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
September 29, 2015
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Energy XXI Ltd
We have audited the accompanying consolidated balance sheet of Energy XXI Ltd (formerly Energy XXI (Bermuda) Limited, a Bermuda Corporation) and subsidiaries (the “Company”) as of June 30, 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two fiscal years in the period ended June 30, 2014. Our audit also included the financial statement schedule included in Item 15(a)(2) as of June 30, 2014, and for each of the two fiscal years in the period ended June 30, 2014. The Company’s management is responsible for these consolidated financial statements and schedule. Our responsibility is to express an opinion on these consolidated financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Energy XXI Ltd and subsidiaries as of June 30, 2014, and the consolidated results of their operations and their cash flows for each of the two fiscal years in the period ended June 30, 2014, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the related financial statement schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ UHY LLP | ||
Houston, Texas | ||
August 25, 2014, except for the effects of the restatement disclosed in Note 22, as to which the date is September 29, 2015 |
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ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS
(In Thousands, except share information)
June 30, 2015 | June 30, 2014 (Restated) | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 756,848 | $ | 145,806 | ||||
Accounts receivable | ||||||||
Oil and natural gas sales | 100,243 | 167,075 | ||||||
Joint interest billings | 12,433 | 12,898 | ||||||
Other | 43,513 | 5,438 | ||||||
Prepaid expenses and other current assets | 24,298 | 72,530 | ||||||
Deferred income taxes | — | 52,587 | ||||||
Restricted cash | 9,359 | — | ||||||
Derivative financial instruments | 22,229 | 1,425 | ||||||
Total Current Assets | 968,923 | 457,759 | ||||||
Property and Equipment | ||||||||
Oil and natural gas properties, net – full cost method of accounting, including $436.4 million and $1,165.7 million of unevaluated properties not being amortized at June 30, 2015 and 2014, respectively | 3,570,759 | 6,427,263 | ||||||
Other property and equipment, net | 21,820 | 19,760 | ||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 3,592,579 | 6,447,023 | ||||||
Other Assets | ||||||||
Goodwill | — | 329,293 | ||||||
Derivative financial instruments | 3,898 | 3,035 | ||||||
Equity investments | 10,835 | 40,643 | ||||||
Restricted cash | 32,667 | 6,350 | ||||||
Other assets and debt issuance costs, net of accumulated amortization | 81,927 | 57,394 | ||||||
Total Other Assets | 129,327 | 436,715 | ||||||
Total Assets | $ | 4,690,829 | $ | 7,341,497 | ||||
LIABILITIES | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 156,339 | $ | 417,776 | ||||
Accrued liabilities | 155,306 | 133,526 | ||||||
Notes payable | — | 21,967 | ||||||
Asset retirement obligations | 33,286 | 79,649 | ||||||
Derivative financial instruments | 2,661 | 31,957 | ||||||
Current maturities of long-term debt | 11,395 | 15,020 | ||||||
Total Current Liabilities | 358,987 | 699,895 | ||||||
Long-term debt, less current maturities | 4,597,037 | 3,744,624 | ||||||
Deferred income taxes | — | 666,969 | ||||||
Asset retirement obligations | 453,799 | 480,185 | ||||||
Derivative financial instruments | 1,358 | 4,306 | ||||||
Other liabilities | 8,370 | 10,958 | ||||||
Total Liabilities | 5,419,551 | 5,606,937 |
See accompanying Notes to Consolidated Financial Statements
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ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS – (continued)
(In Thousands, except share information)
June 30, 2015 | June 30, 2014 (Restated) | |||||||
Commitments and Contingencies (Note 16) | ||||||||
Stockholders’ Equity (Deficit) | ||||||||
Preferred stock, $0.001 par value, 7,500,000 shares authorized at June 30, 2015 and 2014 | ||||||||
7.25% Convertible perpetual preferred stock, 3,000 and 8,000 shares issued and outstanding at June 30, 2015 and 2014, respectively | $ | — | $ | — | ||||
5.625% Convertible perpetual preferred stock, 812,759 and 812,760 shares issued and outstanding at June 30, 2015 and 2014, respectively | 1 | 1 | ||||||
Common stock, $0.005 par value, 200,000,000 shares authorized and 94,643,498 and 93,719,570 shares issued and outstanding at June 30, 2015 and 2014, respectively | 472 | 468 | ||||||
Additional paid-in capital | 1,843,918 | 1,837,462 | ||||||
Accumulated deficit | (2,573,113 | ) | (103,371 | ) | ||||
Total Stockholders’ Equity (Deficit) | (728,722 | ) | 1,734,560 | |||||
Total Liabilities and Stockholders’ Equity (Deficit) | $ | 4,690,829 | $ | 7,341,497 |
See accompanying Notes to Consolidated Financial Statements
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ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, except per share information)
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Revenues | ||||||||||||
Oil sales | $ | 1,052,731 | $ | 1,104,208 | $ | 1,067,687 | ||||||
Natural gas sales | 117,282 | 135,883 | 112,753 | |||||||||
Gain (loss) on derivative financial instruments | 235,439 | (86,968 | ) | (21,508 | ) | |||||||
Total Revenues | 1,405,452 | 1,153,123 | 1,158,932 | |||||||||
Costs and Expenses | ||||||||||||
Lease operating | 463,535 | 365,747 | 337,163 | |||||||||
Production taxes | 8,385 | 5,427 | 5,246 | |||||||||
Gathering and transportation | 21,144 | 23,532 | 24,168 | |||||||||
Depreciation, depletion and amortization | 705,521 | 414,026 | 363,791 | |||||||||
Accretion of asset retirement obligations | 50,081 | 30,183 | 30,885 | |||||||||
Impairment of oil and natural gas properties | 2,421,884 | — | — | |||||||||
Goodwill impairment | 329,293 | — | — | |||||||||
General and administrative expense | 116,500 | 96,402 | 71,598 | |||||||||
Total Costs and Expenses | 4,116,343 | 935,317 | 832,851 | |||||||||
Operating Income (Loss) | (2,710,891 | ) | 217,806 | 326,081 | ||||||||
Other Income (Expense) | ||||||||||||
Loss from equity method investees | (17,165 | ) | (5,231 | ) | (6,010 | ) | ||||||
Other income, net | 4,176 | 3,298 | 1,965 | |||||||||
Interest expense | (323,308 | ) | (162,728 | ) | (108,659 | ) | ||||||
Total Other Expense, net | (336,297 | ) | (164,661 | ) | (112,704 | ) | ||||||
Income (Loss) Before Income Taxes | (3,047,188 | ) | 53,145 | 213,377 | ||||||||
Income Tax Expense (Benefit) | (613,350 | ) | 35,020 | 32,594 | ||||||||
Net Income (Loss) | (2,433,838 | ) | 18,125 | 180,783 | ||||||||
Preferred Stock Dividends | 11,468 | 11,489 | 11,496 | |||||||||
Net Income (Loss) Attributable to Common Stockholders | $ | (2,445,306 | ) | $ | 6,636 | $ | 169,287 | |||||
Earnings (Loss) per Share | ||||||||||||
Basic | $ | (25.97 | ) | $ | 0.09 | $ | 2.14 | |||||
Diluted | $ | (25.97 | ) | $ | 0.09 | $ | 1.94 | |||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||
Basic | 94,167 | 74,375 | 79,063 | |||||||||
Diluted | 94,167 | 74,445 | 87,263 |
See accompanying Notes to Consolidated Financial Statements
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ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In Thousands)
Preferred Stock | Common Stock Shares | Common Stock | Treasury Stock Shares | Treasury Stock | Paid-in Capital | Accumulated (Deficit) (Restated) | Total Stockholders’ Equity (Deficit) (Restated) | |||||||||||||||||||||||||||||
5.625% | 7.25% | |||||||||||||||||||||||||||||||||||
Balance, June 30, 2012 (Restated) | $ | 1 | $ | — | 79,147 | $ | 396 | — | $ | — | $ | 1,501,785 | $ | (215,406 | ) | $ | 1,286,776 | |||||||||||||||||||
Common stock issued, net of direct costs | — | — | 278 | 1 | — | — | 7,021 | — | 7,022 | |||||||||||||||||||||||||||
Common stock based compensation | — | — | — | — | — | — | 3,505 | — | 3,505 | |||||||||||||||||||||||||||
Repurchase of company common stock | — | — | — | — | 2,939 | (72,663 | ) | — | — | (72,663 | ) | |||||||||||||||||||||||||
Common stock dividends | — | — | — | — | — | — | — | (25,992 | ) | (25,992 | ) | |||||||||||||||||||||||||
Preferred stock dividends | — | — | — | — | — | — | — | (11,496 | ) | (11,496 | ) | |||||||||||||||||||||||||
Net Income | — | — | — | — | — | — | — | 180,783 | 180,783 | |||||||||||||||||||||||||||
Balance, June 30, 2013 (Restated) | 1 | — | 79,425 | 397 | 2,939 | (72,663 | ) | 1,512,311 | (72,111 | ) | 1,367,935 | |||||||||||||||||||||||||
Common stock issued, net of direct costs | — | — | 16,382 | 81 | — | — | 341,478 | — | 341,559 | |||||||||||||||||||||||||||
Common stock based compensation | — | — | — | — | — | — | 6,711 | — | 6,711 | |||||||||||||||||||||||||||
Repurchase of company common stock | — | — | — | — | 6,477 | (170,266 | ) | — | — | (170,266 | ) | |||||||||||||||||||||||||
Treasury stock retired | — | — | (2,087 | ) | (10 | ) | (2,087 | ) | 52,966 | (52,956 | ) | — | — | |||||||||||||||||||||||
Common stock reissued | — | — | — | — | (7,329 | ) | 189,963 | (32,030 | ) | (3,216 | ) | 154,717 | ||||||||||||||||||||||||
Discount on convertible debt | — | — | — | — | — | — | 61,948 | — | 61,948 | |||||||||||||||||||||||||||
Common stock dividends | — | — | — | — | — | — | — | (34,680 | ) | (34,680 | ) | |||||||||||||||||||||||||
Preferred stock dividends | — | — | — | — | — | — | — | (11,489 | ) | (11,489 | ) | |||||||||||||||||||||||||
Net Income | — | — | — | — | — | — | — | 18,125 | 18,125 | |||||||||||||||||||||||||||
Balance, June 30, 2014 (Restated) | 1 | — | 93,720 | 468 | — | — | 1,837,462 | (103,371 | ) | 1,734,560 | ||||||||||||||||||||||||||
Common stock issued, net of direct costs | — | — | 923 | 4 | — | — | 2,332 | — | 2,336 | |||||||||||||||||||||||||||
Common stock based compensation | — | — | — | — | — | — | 4,124 | — | 4,124 | |||||||||||||||||||||||||||
Common stock dividends | — | — | — | — | — | — | — | (24,436 | ) | (24,436 | ) | |||||||||||||||||||||||||
Preferred stock dividends | — | — | — | — | — | — | — | (11,468 | ) | (11,468 | ) | |||||||||||||||||||||||||
Net Loss | — | — | — | — | — | — | — | (2,433,838 | ) | (2,433,838 | ) | |||||||||||||||||||||||||
Balance, June 30, 2015 | $ | 1 | $ | — | 94,643 | $ | 472 | — | $ | — | $ | 1,843,918 | $ | (2,573,113 | ) | $ | (728,722 | ) |
See accompanying Notes to Consolidated Financial Statements
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ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Cash Flows From Operating Activities | ||||||||||||
Net income (loss) | $ | (2,433,838 | ) | $ | 18,125 | $ | 180,783 | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||
Depreciation, depletion and amortization | 705,521 | 414,026 | 363,791 | |||||||||
Impairment of oil and natural gas properties | 2,421,884 | — | — | |||||||||
Goodwill impairment | 329,293 | — | — | |||||||||
Deferred income tax expense (benefit) | (614,383 | ) | 31,379 | 19,722 | ||||||||
Change in fair value of derivative financial instruments | (52,036 | ) | 69,656 | 20,851 | ||||||||
Accretion of asset retirement obligations | 50,081 | 30,183 | 30,885 | |||||||||
Loss from equity method investees | 17,165 | 5,231 | 6,010 | |||||||||
Amortization and write-off of debt issuance costs and other | 23,247 | 13,774 | 6,898 | |||||||||
Stock-based compensation | 4,124 | 6,711 | 3,505 | |||||||||
Changes in operating assets and liabilities | ||||||||||||
Accounts receivable | 51,284 | 63,283 | 1,690 | |||||||||
Prepaid expenses and other assets | 48,062 | 6,019 | 12,499 | |||||||||
Settlement of asset retirement obligations | (106,573 | ) | (57,391 | ) | (41,939 | ) | ||||||
Accounts payable and accrued liabilities | (113,078 | ) | (55,536 | ) | 33,453 | |||||||
Net Cash Provided by Operating Activities | 330,753 | 545,460 | 638,148 | |||||||||
Cash Flows from Investing Activities | ||||||||||||
Acquisitions, net of cash | (301 | ) | (849,641 | ) | (161,164 | ) | ||||||
Capital expenditures | (723,829 | ) | (788,676 | ) | (816,105 | ) | ||||||
Insurance payments received | 3,920 | 1,983 | — | |||||||||
Change in equity method investments | 12,642 | (34,294 | ) | (16,693 | ) | |||||||
Transfers to restricted cash | (14,676 | ) | (325 | ) | — | |||||||
Proceeds from the sale of properties | 261,931 | 126,265 | — | |||||||||
Other | (135 | ) | 113 | (41 | ) | |||||||
Net Cash Used in Investing Activities | (460,448 | ) | (1,544,575 | ) | (994,003 | ) | ||||||
Cash Flows from Financing Activities | ||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,336 | 3,994 | 7,021 | |||||||||
Proceeds from convertible debt allocated to additional paid-in capital | — | 63,432 | — | |||||||||
Repurchase of company common stock | — | (184,263 | ) | (58,666 | ) | |||||||
Dividends to shareholders – common | (24,436 | ) | (34,680 | ) | (25,992 | ) | ||||||
Dividends to shareholders – preferred | (11,468 | ) | (11,489 | ) | (11,496 | ) | ||||||
Cash restricted under revolving credit facility related to property sold | (21,000 | ) | — | — | ||||||||
Proceeds from long-term debt | 2,586,572 | 3,420,873 | 1,576,551 | |||||||||
Payments on long-term debt | (1,747,849 | ) | (2,079,485 | ) | (1,243,848 | ) | ||||||
Debt issuance costs | (43,352 | ) | (33,461 | ) | (4,805 | ) | ||||||
Other | (66 | ) | — | 3 | ||||||||
Net Cash Provided by Financing Activities | 740,737 | 1,144,921 | 238,768 | |||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 611,042 | 145,806 | (117,087 | ) | ||||||||
Cash and Cash Equivalents, beginning of period | 145,806 | — | 117,087 | |||||||||
Cash and Cash Equivalents, end of period | $ | 756,848 | $ | 145,806 | $ | — |
See accompanying Notes to Consolidated Financial Statements
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 1 — Organization and Summary of Significant Accounting Policies
Nature of Operations. Energy XXI Ltd was incorporated in Bermuda on July 25, 2005. References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. With our principal operating subsidiary 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 in the Gulf of Mexico Shelf (“GoM Shelf”). We are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI.”
Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence. The consolidated financial statements for the previous periods include certain reclassifications that were made to conform to the current presentation. Such reclassifications did not have a significant impact on previously reported consolidated net income, consolidated stockholders’ equity or consolidated cash flows. In addition, we have restated previously issued consolidated financial statements to reflect the recognition of gains and losses on derivative financial instruments previously included in accumulated other comprehensive income (loss) as gain (loss) on derivative financial instruments in earnings as a component of revenues and the reclassification of amounts associated with settled contracts previously included in oil and gas sales revenues to gain (loss) on derivative financial instruments as a result of not qualifying for cash flow hedge accounting treatment. The restatement also reflects resulting adjustments to net oil and natural gas properties, impairment of oil and natural gas properties and depreciation, depletion and amortization due to the previous inclusion of the value of the cash flow hedges in our full cost ceiling test, which is only permitted if the derivative instruments qualify for cash flow hedge accounting. Additionally, resulting adjustments to deferred income taxes and income tax expense (benefit) are also reflected in the restatement. See Note 22 — Restatement of Previously Issued Consolidated Financial Statements for details of the impact of the restatement.
Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
Cash and Cash Equivalents. We consider all highly liquid investments, with maturities of 90 days or less when purchased, to be cash and cash equivalents.
Restricted Cash. We maintain restricted escrow funds in trusts as required by certain contractual arrangements and disposition transactions. Amounts on deposit in trust accounts are reflected in Restricted cash on our consolidated balance sheets.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable are stated at historical carrying amount net of allowance for doubtful accounts. We establish provisions for losses on accounts receivable if it is determined that collection of all or a part of an outstanding balance is not probable.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 1 — Organization and Summary of Significant Accounting Policies – (continued)
Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. As of June 30, 2015 and 2014, no allowance for doubtful accounts was necessary.
Oil and Natural Gas Properties. We use the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.
Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Costs excluded from depletion or amortization represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.
We evaluate the impairment of our evaluated oil and natural gas properties through the use of a ceiling test as prescribed by SEC Regulation S-X Rule 4-10. Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. Such cost estimates related to future development costs of proved oil and natural gas reserves could be subject to revisions due to changes in regulatory requirements, technological advances and other factors which are difficult to predict.
Depreciation, Depletion and Amortization. The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, amortization and impairment, estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-production method over total proved reserves.
Weather Based Insurance Linked Securities. We obtain Weather Based Insurance Linked Securities (“Securities”), to mitigate potential loss to our oil and natural gas properties from hurricanes in the Gulf of Mexico. These Securities provide for payments of negotiated amounts should a pre-defined category hurricane pass within specific pre-defined areas encompassing our oil and natural gas producing fields. Since these Securities were obtained to mitigate potential loss due to hurricanes in the Gulf of Mexico, the majority of the premiums associated with these Securities are charged to expense during the period associated with the hurricane season, typically June 1 to November 30. The amortization of insurance premiums for these Securities is recorded as a component of our lease operating expense.
Other Property and Equipment. Other property and equipment include buildings, data processing and telecommunications equipment, office furniture and equipment, vehicle and leasehold improvements and other fixed assets. These items are recorded at cost and are depreciated using the straight-line method based on expected lives of the individual assets or group of assets, which ranges from three to five years. Repairs and maintenance costs are expensed in the period incurred.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 1 — Organization and Summary of Significant Accounting Policies – (continued)
Business Combinations. For properties acquired in a business combination, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes are recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of the purchase price over amounts assigned to assets and liabilities is recorded as goodwill. Any excess of amounts assigned to assets and liabilities over the purchase price is recorded as a gain on bargain purchase. The amount of goodwill or gain on bargain purchase recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed.
In estimating the fair values of assets acquired and liabilities assumed in a business combination, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Goodwill. Goodwill has an indefinite useful life and is not amortized, but rather is tested for impairment at least annually during the third quarter, unless events occur or circumstances change between annual tests that would more likely than not reduce the fair value of a related reporting unit below its carrying value. Impairment occurs when the carrying amount of goodwill exceeds its implied fair value. Goodwill arose in the year ended June 30, 2014 in connection with the acquisition of EPL Oil & Gas, Inc. and was recorded to our oil and gas reporting unit. At December 31, 2014, we conducted a qualitative goodwill impairment assessment and after assessing the relevant events and circumstances, we determined that performing a quantitative goodwill impairment test was necessary. Therefore, we performed steps one and two of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 — “Goodwill” for more information.
Derivative Instruments. We utilize derivative instruments in the form of natural gas and crude oil put, swap and collar arrangements and combinations of these instruments in order to manage the price risk associated with future crude oil and natural gas production. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We net derivative assets and liabilities for counterparties where we have a legal right of offset. Any premiums paid or financed on derivative financial instruments are capitalized as part of the derivative assets or derivative liabilities, as appropriate, at the time the premiums are paid or financed.
We previously designated the majority of our derivative instruments as cash flow hedges, however, in connection with preparing our Form 10-K for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges related to our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 1 — Organization and Summary of Significant Accounting Policies – (continued)
meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, our currently outstanding derivative contracts are not accounted for as cash flow hedges. Therefore, changes in fair value of these outstanding derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statement of operations.
Additionally, we concluded that certain of our previously issued consolidated financial statements should no longer be relied upon and would need to be restated. This Form 10-K for the year ended June 30, 2015 includes (1) a restated balance sheet as of June 30, 2014, (2) restated consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended June 30, 2014 and 2013, (3) restated consolidated quarterly financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, March 31, 2015 and 2014, and (4) restated consolidated quarterly financial information for June 30, 2014, and (5) restated selected financial data for the years ended June 30, 2014, 2013, 2012, and 2011. See Notes 22 and 23 of the notes to the Consolidated Financial Statements, for more information concerning these restatements.
Debt Issuance Costs. Costs incurred in connection with the issuance of long-term debt are capitalized and amortized to interest expense over the scheduled maturity of the debt utilizing the interest method.
Asset Retirement Obligations. Our investment in oil and natural gas properties includes an estimate of the future cost associated with dismantlement, abandonment and restoration of our properties. The present value of the future costs are added to the capitalized cost of our oil and natural gas properties and recorded as a long-term or current liability. The capitalized cost is included in oil and natural gas properties that are depleted over the life of the assets. The estimation of future costs associated with dismantlement, abandonment and restoration requires the use of estimated costs in future periods that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.
Common Stock. Refers to the $0.005 par value per share capital stock as designated in the Company’s Certificate of Incorporation. Treasury Stock is accounted for using the cost method.
Revenue Recognition. We recognize oil and natural gas revenue when the product is delivered at the contracted sales price, title is transferred and collectability is reasonably assured. The Company has elected the entitlements method to account for gas production imbalances. Gas imbalances occur when we sell more or less than our entitled ownership percentage of total gas production. Any amount received in excess of our share is treated as a liability. If we receive less than our entitled share the underproduction is recorded as a receivable. The amounts of imbalances were not material at June 30, 2015 and 2014.
General and Administrative Expense. Under the full cost method of accounting, the portion of our general and administrative expense that is directly identified with our acquisition, exploration and development activities is capitalized as part of our oil and natural gas properties. These capitalized costs include salaries, employee benefits, costs of consulting services, and other direct costs incurred to support those employees directly involved in acquisition, exploration and development activities. The capitalized costs do not include costs related to production operations, general corporate overhead or similar activities. Our capitalized general and administrative expense directly related to our acquisition, exploration and development activities for the years ended June 30, 2015, 2014 and 2013 was $49.2 million, $64.5 million, and $37.6 million, respectively.
Share-Based Compensation. Compensation cost for equity awards is based on the fair value of the equity instrument on the date of grant and is recognized over the period during which an employee is required
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 1 — Organization and Summary of Significant Accounting Policies – (continued)
to provide service in exchange for the award. Compensation cost for liability awards is based on the fair value of the vested award at the end of each reporting period.
Income Taxes. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and natural gas properties and derivative instruments for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, we may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs where management deems appropriate.
When recording income tax expense, certain estimates are required to be made by management due to timing and to the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate any tax operating loss and other carryforwards to determine whether a gross tax asset, as well as a valuation allowance, should be recognized in our consolidated financial statements. In light of the results of operations for the current year (heavily affected by impairments) we recorded an increase in our valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana net operating loss (“NOL”) carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly. In light of our capital structure, U.S. withholding taxes attributable to interest due on loans from the Bermuda parent to the U.S. operating companies is provided as the interest accrues. This U.S. withholding tax at 30% is due when the interest is actually paid, and may not be offset or reduced by U.S. operating activity; although the interest expense is generally deductible in the U.S. when paid, subject to certain other limitations.
Earnings per Share. Basic earnings (loss) per share (“EPS”) amounts have been calculated based on the weighted-average number of shares of common stock outstanding for the year. Diluted EPS reflects potential dilution using the treasury stock method. Except when the effect would be anti-dilutive, the diluted EPS calculation includes the impact of the assumed conversion of our convertible preferred stock and other potential shares of common stock.
Note 2 — Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.
In August 2014, the FASB issued ASU No. 2014-15,Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 2 — Recent Accounting Pronouncements – (continued)
periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
In April 2015, the FASB issued ASU No. 2015-03,Interest — Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.
Note 3 — Acquisitions and Dispositions
Black Elk Interest Acquisition
On December 20, 2013, we acquired certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013, and we are currently the operator of these properties.
Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):
Oil and natural gas properties – evaluated | $ | 15,821 | ||
Oil and natural gas properties – unevaluated | 6,586 | |||
Asset retirement obligations | (10,503 | ) | ||
Net working capital * | (1,500 | ) | ||
Cash paid | $ | 10,404 |
* | Net working capital includes payables. |
Walter Oil & Gas Corporation Oil and Gas Property Interests Acquisition
On March 7, 2014, we acquired certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million. This acquisition was effective January 1, 2014, and we are currently the operator of these properties.
Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):
Oil and natural gas properties – evaluated | $ | 23,497 | ||
Asset retirement obligations | (705 | ) | ||
Cash paid | $ | 22,792 |
We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 3 — Acquisitions and Dispositions – (continued)
of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; (3) an inflation factor; and (4) a credit adjusted risk-free interest rate. Fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 19 — Fair Value of Financial Instruments.
EPL Oil & Gas, Inc. (“EPL”) Acquisition
We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.
In connection with the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”) or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election” and together with the Cash Election and the Stock Election, the “Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30, 2014 deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of Energy XXI common stock and paid approximately $1,012 million in cash.
The following table summarizes the total purchase price of approximately $1,504.3 million, including cash acquired of $206.1 million (in millions,except per share amounts):
Election | EPL Shares | Cash per share | Energy XXI Stock | Cash Paid | Energy XXI Stock Issued | Energy XXI Stock Price on June 3, 2014 | Cash Value of Energy XXI Stock Issued | Total Purchase Price | ||||||||||||||||||||||||
Cash Election | 30.6 | $ | 25.92 | 0.5595 | $ | 792.6 | 17.1083 | $ | 21.11 | $ | 361.2 | $ | 1,153.8 | |||||||||||||||||||
Mixed Election | 7.4 | 25.35 | 0.5840 | 186.8 | 4.3037 | 21.11 | 90.8 | 277.6 | ||||||||||||||||||||||||
Stock Election | 1.1 | — | 1.6690 | — | 1.9090 | 21.11 | 40.3 | 40.3 | ||||||||||||||||||||||||
Stock Options | 0.8 | 39.00 | — | 32.6 | — | — | 32.6 | |||||||||||||||||||||||||
Total | 39.9 | $ | 1,012.0 | 23.3210 | $ | 492.3 | $ | 1,504.3 |
(*) | Includes 4.7 million EPL shares that were held by EPL stockholders that did not make an election prior to the May 30, 2014 election deadline. |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 3 — Acquisitions and Dispositions – (continued)
The following table summarizes the final purchase price allocation for EPL as of June 3, 2014 (in thousands):
EPL Historical | Fair Value Adjustment | Total | ||||||||||
(Unaudited) | ||||||||||||
Current assets (excluding deferred income taxes) | $ | 301,592 | $ | 1,274 | $ | 302,866 | ||||||
Oil and natural gas properties(a) | ||||||||||||
Evaluated (Including net ARO assets) | 1,919,699 | 112,624 | 2,032,323 | |||||||||
Unevaluated | 41,896 | 859,886 | 901,782 | |||||||||
Other property and equipment | 7,787 | — | 7,787 | |||||||||
Other assets | 16,227 | (9,002 | ) | 7,225 | ||||||||
Current liabilities (excluding ARO) | (314,649 | ) | (2,058 | ) | (316,707 | ) | ||||||
ARO (current and long-term) | (260,161 | ) | (13,211 | ) | (273,372 | ) | ||||||
Debt (current and long-term) | (973,440 | ) | (52,967 | ) | (1,026,407 | ) | ||||||
Deferred income taxes(b) | (118,359 | ) | (340,645 | ) | (459,004 | ) | ||||||
Other long-term liabilities | (2,242 | ) | 797 | (1,445 | ) | |||||||
Total fair value, excluding goodwill | 618,350 | 556,698 | 1,175,048 | |||||||||
Goodwill(c),(d) | — | 329,293 | 329,293 | |||||||||
Less cash acquired | — | — | 206,075 | |||||||||
Total purchase price | $ | 618,350 | $ | 885,991 | $ | 1,298,266 |
(a) | EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy. |
(b) | Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit). |
(c) | See Note 4 — “Goodwill” for more information regarding goodwill impairment at December 31, 2014. |
(d) | On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million. Accordingly, the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill. |
In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 3 — Acquisitions and Dispositions – (continued)
The fair value estimates of the oil and natural gas properties, and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.
The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 — “Goodwill” for more information regarding the impairment of goodwill at December 31, 2014.
In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the year ended June 30, 2015, our consolidated statement of operations includes EPL’s operating revenues of $542.8 million and net loss of $1,298.7 million.
The following supplemental unaudited pro forma consolidated financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on the historical consolidated statements of operations of Energy XXI and EPL for the years ended June 30, 2014 and 2013 (in thousands,except per share amounts).
Year Ended June 30, | ||||||||
2014 (Restated) | 2013 (Restated) | |||||||
Revenues | $ | 1,783,062 | $ | 1,877,322 | ||||
Net income (loss) | (45,233 | ) | 223,805 | |||||
Net income (loss) available to Energy XXI common stockholders | (56,722 | ) | 212,309 | |||||
Net loss per share available to Energy XXI common stockholders: | ||||||||
Basic | $ | (0.76 | ) | $ | 2.69 | |||
Diluted | $ | (0.76 | ) | $ | 2.43 |
The above restated supplemental unaudited pro forma consolidated financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments to income from continuing operations for the years ended June 30, 2014 and 2013 were the following:
a. | Exclude expense of $45.2 million and $15.7 million, respectively, of EPL’s exploration costs and impairment expense and $1.8 million and $26.9 million, respectively, of gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting. |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 3 — Acquisitions and Dispositions – (continued)
b. | Increase DD&A expense by $65.3 million and $120.5 million, respectively, for the EPL Properties to correspond with EXXI’s full cost method of accounting as well as the adjustments to fair value of the acquired assets. |
c. | Increase interest expense by $50.0 million and $54.0 million, respectively, to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 (the “6.875% Senior Notes”) and on additional borrowings under EXXI’s revolving credit facility. Decrease interest expense $12.3 million and $13.3 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million 8.25% senior notes due 2018 (the “8.25% Senior Notes”) assumed in the EPL Acquisition. |
Sale of interests in the Eugene Island 330 and the South Marsh Island 128 fields
On April 1, 2014, we sold our interests in the Eugene Island 330 and the South Marsh Island 128 fields to M21K, LLC (“M21K”), which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million.
Sale of the Grand Isle Gathering System
On June 30, 2015, we sold certain real and personal property constituting a subsea pipeline gathering system located in the shallow GoM shelf and storage and onshore processing facilities on Grand Isle, Louisiana (the “GIGS”) to Grand Isle Corridor, LP (“Grand Isle Corridor”), a wholly-owned subsidiary of CorEnergy Infrastructure Trust, Inc. (“CorEnergy) for cash consideration of $245 million, plus the assumption by Grand Isle Corridor of the asset retirement obligations associated with the estimated decommissioning costs for the GIGS. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $248.9 million. Also on June 30, 2015, we entered into a triple-net lease agreement with Grand Isle Corridor pursuant to which we will continue to use and operate the GIGS as further discussed in Note 16 — “Commitments and Contingencies”.
Sale of interests in the East Bay field
On June 30, 2015, we sold our interest in the East Bay field to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC, for cash consideration of $21 million plus the assumption of asset retirement obligations estimated at $55.1 million. The cash consideration is payable in two installments with $5 million received at closing and the remainder due on or before October 31, 2015. We retained a 5% overriding royalty interest (applicable only during calendar months if and when the WTI for such month averages over $65) on these assets for a period not to exceed 5 years from the closing date or $7 million whichever occurs first, and we also retained 50% of the deep rights associated with the East Bay field. Revenues and expenses related to the field were included in our results of operations through June 30, 2015. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $68.9 million.
Note 4 — Goodwill
ASC 350,Intangibles — Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed at least annually during the third quarter.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 4 — Goodwill – (continued)
Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.
At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. In light of the form of the acquisition of EPL (a purchase of stock), this goodwill had no tax basis when recognized, which resulted in no income tax benefit when impaired.
In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using an assumed weighted average cost of capital based on market participant data. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Note 5 — Property and Equipment
Property and equipment consists of the following (in thousands):
June 30, 2015 | June 30, 2014 (Restated) | |||||||
Oil and gas properties | ||||||||
Proved properties | $ | 9,243,737 | $ | 8,247,352 | ||||
Less: accumulated depreciation, depletion, amortization and impairment | 6,109,335 | 2,985,790 | ||||||
Proved properties, net | 3,134,402 | 5,261,562 | ||||||
Unevaluated properties | 436,357 | 1,165,701 | ||||||
Oil and gas properties, net | 3,570,759 | 6,427,263 | ||||||
Other property and equipment | 45,941 | 39,272 | ||||||
Less: accumulated depreciation | 24,121 | 19,512 | ||||||
Other property and equipment, net | 21,820 | 19,760 | ||||||
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment | $ | 3,592,579 | $ | 6,447,023 |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 5 — Property and Equipment – (continued)
The following table summarizes an aging of total costs related to unevaluated properties excluded from the amortization base as of June 30, 2015(in thousands).
Net Costs Incurred During the Years Ended June 30, | Balance as of June 30, 2015 | |||||||||||||||||||
2012 and prior | 2013 | 2014 | 2015 | |||||||||||||||||
Unevaluated Properties (acquisition costs) | $ | 928 | $ | — | $ | 435,429 | $ | — | $ | 436,357 |
At June 30, 2015, our investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL Acquisition). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) ratably over a period of time of not more than four years.
At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties. Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following: 1) the Lomond North project resulted in a successful production test with commercial production commencing in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired. Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the year ended June 30, 2015.
Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. At June 30, 2015, our ceiling test computation resulted in impairment of our oil and natural gas properties totaling $2,421.9 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.
Note 6 — Equity Method Investments
Through June 30, 2015, we owned a 20% interest in EXXI M21K, which engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K. EGC, an indirect wholly owned subsidiary of Energy XXI Ltd, received a management fee from M21K for providing administrative assistance in carrying out its operations. See Note 14 — “Related Party Transactions”.
Since its inception in February 2012, M21K completed three acquisitions for aggregate cash consideration of approximately $284.1 million. In July 2012, it acquired oil and gas interests from EP Energy E&P Company, L.P. for approximately $80.4 million. In August 2013, it acquired oil and gas interests from LLOG Exploration Offshore, L.L.C. for approximately $80.8 million. In April 2014, it acquired oil and gas
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 6 — Equity Method Investments – (continued)
interests from Energy XXI GOM, LLC (“EXXI GOM”), an indirect wholly owned subsidiary of Energy XXI Ltd, for approximately $122.9 million. We provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K related to these acquisitions.
EXXI M21K was a guarantor of a $100 million first lien credit facility agreement entered into by M21K, which had a $40 million borrowing base and under which $28.0 million in loans and $1.2 million in letters of credit were outstanding as of June 30, 2015. At June 30, 2015, M21K was in default due to a breach of certain covenants under this agreement. On August 11, 2015, we acquired all of the equity interests of M21K for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing. See Note 21 — “Subsequent Events.”
As of June 30, 2015, our investment in EXXI M21K was approximately $10.8 million. We recorded an equity loss of $17.4 million, $4.3 million and $2.5 million for the years ended June 30, 2015, 2014 and 2013, respectively. The equity loss for the year ended June 30, 2015 includes an other-than-temporary impairment related to our investment in EXXI M21K of $11.8 million.
Note 7 — Long-Term Debt
Long-term debt consists of the following (in thousands):
June 30, | ||||||||
2015 | 2014 | |||||||
Revolving Credit Facility | $ | 150,000 | $ | 689,000 | ||||
11.0% Senior Secured Second Lien Notes due 2020 | 1,450,000 | — | ||||||
8.25% Senior Notes due 2018 | 510,000 | 510,000 | ||||||
6.875% Senior Notes due 2024 | 650,000 | 650,000 | ||||||
3.0% Senior Convertible Notes due 2018 | 400,000 | 400,000 | ||||||
7.5% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
7.75% Senior Notes due 2019 | 250,000 | 250,000 | ||||||
9.25% Senior Notes due 2017 | 750,000 | 750,000 | ||||||
4.14% Promissory Note due 2017 | 4,343 | 4,774 | ||||||
Debt premium, 8.25% Senior Notes due 2018(1) | 29,459 | 40,566 | ||||||
Original issue discount, 11.0% Notes due 2020 | (51,104 | ) | — | |||||
Original issue discount, 3.0% Senior Convertible Notes due 2018 | (45,782 | ) | (57,014 | ) | ||||
Derivative instruments premium financing | 10,647 | 21,000 | ||||||
Capital lease obligations | 869 | 1,318 | ||||||
Total debt | 4,608,432 | 3,759,644 | ||||||
Less current maturities | 11,395 | 15,020 | ||||||
Total long-term debt | $ | 4,597,037 | $ | 3,744,624 |
(1) | Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition. |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
Maturities of long-term debt as of June 30, 2015 are as follows (in thousands):
Twelve Months Ending June 30, | ||||
2016 | $ | 11,395 | ||
2017 | 750,810 | |||
2018 | 693,113 | |||
2019 | 620,541 | |||
2020 | 1,450,000 | |||
Thereafter | 1,150,000 | |||
4,675,859 | ||||
Less: Net original issue discount & debt premium | (67,427 | ) | ||
Total debt | $ | 4,608,432 |
Revolving Credit Facility
On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated First Lien Credit Agreement in connection with the issuance of $1.45 billion of senior secured second lien notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020.” Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:
• | reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement; |
• | addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements; |
• | change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018; |
• | elimination, addition, or modification of certain financial covenants; |
• | setting the applicable commitment fee under the First Lien Credit Agreement at 0.50% and providing that outstanding amounts drawn under the First Lien Credit Agreement bear interest at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%; |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
• | increase of the threshold requirement for oil and gas properties required to be secured by mortgages to 90% of the value of EGC and its subsidiaries’ (other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but allowing the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) to remain at 85%; |
• | addition of certain further restrictions on the prepayment and repayment of outstanding note indebtedness of EGC and its subsidiaries, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that EGC have net liquidity at the time thereof of at least $250 million; |
• | modification to the restricted payment covenant to substantially limit the ability of EGC to make distributions and dividends to parent entities, provided that a distribution of the GIGS was permitted; |
• | qualification on the ability of EGC and its subsidiaries to refinance outstanding indebtedness by requiring that EGC have pro forma net liquidity of $250 million at the time of such refinancing; and |
• | modification of the asset disposition covenant to require lender consent for any such disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate; provided, however, that such provision was expressly deemed not to be applicable to certain sales relating to the GIGS, as long as EGC and its subsidiaries meet certain obligations, such as, among others, maintaining the proceeds from such sales in accounts that are subject to the liens of the lenders. |
As of June 30, 2015, we had $150.0 million in borrowings and $226.0 million in letters of credit issued under the revolving credit facility. During the year ended June 30, 2015, as a result of the reduction in the borrowing capacity under our revolving credit facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.
The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenant on a consolidated basis: a minimum current ratio of no less than 1.0 to 1.0. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If EPL’s 8.25% Senior Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the revolving credit facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.
Under the First Lien Credit Agreement, as amended under the Tenth Amendment, EGC’s rights to make distributions to its shareholders (including ultimately to Energy XXI Ltd) are substantially reduced. Generally, under the Tenth Amendment, EGC is only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to EGC and its subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements. Substantially all the net assets of the Company’s subsidiaries are restricted.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
As of June 30, 2015, we were in compliance with all covenants under the First Lien Credit Agreement, other than with respect to the sale of interests in the East Bay field. Since required lender consent to the specific terms of the transaction had not been obtained, EGC and EPL were in technical default under the First Lien Credit Agreement at June 30, 2015. On July 14, 2015, we obtained a waiver to this event of default, which waiver required EPL to deposit $21 million into an account subject to a control agreement in favor of the administrative agent under the First Lien Credit Agreement. Such amount will remain on deposit until the next redetermination of the borrowing base, unless used to repay a borrowing base deficiency. Upon the next redetermination, any amounts remaining in the account will be used to make an immediate payment toward any borrowing base deficiency at the time of such redetermination, and so long as no event of default shall have occurred, any amount remaining after payment in full of any borrowing base deficiency shall be released and paid to EGC.
As of July 31, 2015, EGC and EPL entered into the Eleventh Amendment and Waiver to the First Lien Credit Agreement (the “Eleventh Amendment”), which waives certain provisions of the First Lien Credit Agreement to permit the M21K acquisition described above as well as an additional minor acquisition and disposition. Further, the Eleventh Amendment temporarily increased the letter of credit commitment amount within the facility from $300 million to a maximum amount of $305 million through August 31, 2015, after which it reduced back to $300 million. Please see Note 21 — “Subsequent Events.”
Based on projected market conditions and commodity prices, we currently expect that we will be in compliance with covenants under our credit agreement at least through June 30, 2016; however, commodity prices have been extremely volatile in recent history and a protracted further decline in commodity prices could cause us to not be in compliance with certain financial covenants under our credit agreements in future periods. A breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. Certain payment defaults or acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.
11.0% Senior Secured Second Lien Notes Due 2020
On March 12, 2015, EGC issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, our ultimate parent company Energy XXI Ltd (the “Parent”), Energy XXI USA, Inc. (“EXXI USA”) and certain of EGC’s wholly owned subsidiaries (together with the Parent and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”). EGC received net proceeds of approximately $1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a price of 96.313% of principal, for a yield to maturity at issuance of 12.0%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. The 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15th and September 15th, beginning September 15, 2015. EGC incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the
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FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
11.0% Notes. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the direct offering costs.
The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The 11.0% Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC, in each case to the extent such assets secure our revolving credit facility. In the future, the 11.0% Notes may be guaranteed by certain of EGC’s material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our revolving credit facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.
The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of EGC’s future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. Although the 11.0% Notes are guaranteed by the Parent and EXXI USA, the Parent and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.
On or after September 15, 2017, EGC will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, EGC may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each holder of the 11.0% Notes will have the right to require EGC to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.
The 2015 Indenture restricts EGC’s ability and the ability of its restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of EGC’s assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.
8.25% Senior Notes Due 2018
On June 3, 2014, EGC assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the
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FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
“2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.
6.875% Senior Notes Due 2024
On May 27, 2014, EGC issued at par $650 million in aggregate principal amount of the 6.875% Senior Notes due March 15, 2024. On June 1, 2015, we completed a registered offer to exchange the 6.875% Senior Notes for a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which were capitalized and are being amortized over the life of the 6.875% Senior Notes.
On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.
The indenture governing the 6.875% Senior Notes, among other things, limits EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
3.0% Senior Convertible Notes due 2018
On November 18, 2013, the Parent sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). We incurred underwriting and direct offering costs of $7.6 million which have been capitalized and are being amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of the Parent, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The
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FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
Upon conversion, the Parent will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the conversion obligation is satisfied solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will receive interest, payable in cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be.
If holders elect to convert the notes in connection with certain fundamental change transactions described in the indenture governing the 3.0% Senior Convertible Notes, the conversion rate will increase by a number of additional shares determined by reference to the provisions contained in the indenture governing the 3.0% Senior Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of common stock in, such make-whole fundamental change. If holders of common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.
If the Parent undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require the Parent to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.
For accounting purposes, the $400 million aggregate principal amount of 3.0% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3.0% Senior Convertible Notes, which has been reflected as additional paid-in capital. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the original issue discount of $63.4 million is being amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.
7.5% Senior Notes Due 2021
On September 26, 2013, EGC issued at par $500 million aggregate principal amount of 7.5% unsecured senior notes due December 15, 2021 (“7.5% Senior Notes”). In April 2014, we completed a registered offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.
On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued
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FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.
The indenture governing the 7.5% Senior Notes limits, among other things, EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
7.75% Senior Notes
On February 25, 2011, EGC issued at par $250 million aggregate principal amount of 7.75% unsecured senior notes due June 15, 2019 (the “7.75% Old Senior Notes”). On July 7, 2011, EGC exchanged the 7.75% Old Senior Notes for newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) with identical terms and conditions.
The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. EGC incurred underwriting and direct offering costs of $3.1 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.
9.25% Senior Notes
On December 17, 2010, EGC issued at par $750 million aggregate principal amount of 9.25% unsecured senior notes due December 15, 2017 (the “9.25% Old Senior Notes”). On July 8, 2011, EGC exchanged $749 million of the 9.25% Old Senior Notes for $749 million of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act with identical terms and conditions. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.
The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. EGC incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.
4.14% Promissory Note
In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make monthly payments of approximately $52,000 and a lump-sum payment of $3.3 million at maturity in October 2017. This note carries an interest rate of 4.14% per annum.
Derivative Instruments Premium Financing
We finance premiums on derivative instruments that we purchase from our hedge counterparties. Substantially all of our hedge transactions are with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings
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FOR THE YEAR ENDED JUNE 30, 2015
Note 7 — Long-Term Debt – (continued)
under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of June 30, 2015 and 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost under our revolving credit facility of 2.5% per annum totaled $10.6 million and $21.0 million, respectively.
Interest Expense
Interest expense consisted of the following (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Revolving Credit Facility | $ | 25,506 | $ | 13,956 | $ | 11,816 | ||||||
11.0% Senior Secured Second Lien Notes due 2020 | 48,505 | — | — | |||||||||
8.25% Senior Notes due 2018 | 42,075 | 3,507 | — | |||||||||
6.875% Senior Notes due 2024 | 44,701 | 4,096 | — | |||||||||
3.0% Senior Convertible Notes due 2018 | 12,000 | 7,266 | — | |||||||||
7.50% Senior Notes due 2021 | 37,500 | 28,542 | — | |||||||||
7.75% Senior Notes due 2019 | 19,375 | 19,375 | 19,375 | |||||||||
9.25% Senior Notes due 2017 | 69,375 | 69,375 | 69,375 | |||||||||
4.14% Promissory Note due 2017 | 192 | 210 | — | |||||||||
Amortization of debt issue cost – revolving credit facility | 12,491 | 3,076 | 4,303 | |||||||||
Accretion of original debt issue discount, 11.0% Notes due 2020 | 2,358 | — | — | |||||||||
Amortization of debt issue cost – 11.0% Notes due 2020 | 1,887 | — | — | |||||||||
Amortization of fair value premium – 8.25% Senior Notes due 2018 | (11,108 | ) | (841 | ) | — | |||||||
Amortization of debt issue cost – 6.875% Senior Notes due 2024 | 1,127 | 102 | — | |||||||||
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 | 11,232 | 6,418 | — | |||||||||
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 | 1,439 | 801 | — | |||||||||
Amortization of debt issue cost – 7.50% Senior Notes due 2021 | 1,051 | 783 | — | |||||||||
Amortization of debt issue cost – 7.75% Senior Notes due 2019 | 388 | 388 | 388 | |||||||||
Amortization of debt issue cost – 9.25% Senior Notes due 2017 | 2,358 | 2,206 | 2,206 | |||||||||
Derivative instruments financing and other | 856 | 987 | 1,196 | |||||||||
Bridge commitment fee | — | 2,481 | — | |||||||||
$ | 323,308 | $ | 162,728 | $ | 108,659 |
Note 8 — Notes Payable
On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million with an annual interest rate of 1.923%. The notes matured and were repaid on May 1, 2015.
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FOR THE YEAR ENDED JUNE 30, 2015
Note 8 — Notes Payable – (continued)
On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million with an annual interest rate of 1.723%. The note matured and was repaid on May 3, 2015.
In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million with an annual interest rate of 1.623%. The note matured and was repaid on April 26, 2014.
Note 9 — Asset Retirement Obligations
The following table describes the changes in our asset retirement obligations (in thousands):
Year Ended June 30, | ||||||||
2015 | 2014 | |||||||
Beginning of period total | $ | 559,834 | $ | 287,818 | ||||
Liabilities acquired | — | 284,661 | ||||||
Liabilities incurred and true-up to liabilities settled | 40,820 | 41,216 | ||||||
Liabilities settled | (106,573 | ) | (57,391 | ) | ||||
Liabilities sold | (65,752 | ) | — | |||||
Revisions in estimated cash flows | 8,675 | (26,653 | ) | |||||
Accretion expense | 50,081 | 30,183 | ||||||
End of period total | 487,085 | 559,834 | ||||||
Less: End of period, current portion | 33,286 | 79,649 | ||||||
End of period, noncurrent portion | $ | 453,799 | $ | 480,185 |
Note 10 — Derivative Financial Instruments
We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. We previously designated the majority of our derivative instruments as cash flow hedges, however, in connection with preparing our Form 10-K for the year ended June 30, 2015, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges related to our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Accordingly, our currently outstanding derivative contracts are not accounted for as cash flow hedges. Therefore, changes in fair value of these outstanding derivative financial instruments are recognized in earnings and included in gain (loss) on derivative financial instruments as a component of revenues in the accompanying consolidated statement of operations.
With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With
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FOR THE YEAR ENDED JUNE 30, 2015
Note 10 — Derivative Financial Instruments – (continued)
a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.
Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.
The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.
Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts, keeping one natural gas contract.
As of June 30, 2015, we had the following net open crude oil derivative positions:
Weighted Average Contract Price | ||||||||||||||||||||||||
Type of Contract | Index | Volumes (MBbls) | Collars/Put | |||||||||||||||||||||
Remaining Contract Term | Sub Floor | Floor | Ceiling | |||||||||||||||||||||
July 2015 – December 2015 | Three-Way Collars | ARGUS-LLS | 3,680 | $ | 32.50 | $ | 45.00 | $ | 75.00 | |||||||||||||||
July 2015 – December 2015 | Collars | ARGUS-LLS | 920 | 80.00 | 123.38 | |||||||||||||||||||
July 2015 – December 2015 | Collars | NYMEX-WTI | 276 | 75.00 | 85.00 | |||||||||||||||||||
July 2015 – December 2015 | Bought Put | NYMEX-WTI | 552 | 90.00 | ||||||||||||||||||||
July 2015 – December 2015 | Sold Put | NYMEX-WTI | (552 | ) | 90.00 | |||||||||||||||||||
January 2016 – June 2016 | Collars | NYMEX-WTI | 2,548 | 51.43 | 74.70 | |||||||||||||||||||
July 2016 – December 2016 | Collars | NYMEX-WTI | 2,576 | 51.43 | 74.70 |
As of June 30, 2015, we had the following net open natural gas derivative position:
Remaining Contract Term | Type of Contract | Index | Volumes (MMBtu) | Swaps Fixed Price | ||||||||||||
July 2015 – December 2015 | Swaps | NYMEX-HH | 791 | $ | 4.31 |
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FOR THE YEAR ENDED JUNE 30, 2015
Note 10 — Derivative Financial Instruments – (continued)
The fair values of derivative instruments in our consolidated balance sheets were as follows(inthousands):
Asset Derivative Instruments | Liability Derivative Instruments | |||||||||||||||||||||||||||||||
June 30, 2015 | June 30, 2014 | June 30, 2015 | June 30, 2014 | |||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||||||||||||||||||
Derivative financial instruments | Current | $ | 51,024 | Current | $ | 17,380 | Current | $ | 31,456 | Current | $ | 47,912 | ||||||||||||||||||||
Non-Current | 11,980 | Non-Current | 9,595 | Non-Current | 9,440 | Non-Current | 10,866 | |||||||||||||||||||||||||
Total Gross Commodity Derivative Instruments subject to enforceable master netting agreement | 63,004 | 26,975 | 40,896 | 58,778 | ||||||||||||||||||||||||||||
Derivative financial instruments | Current | (28,795 | ) | Current | (15,955 | ) | Current | (28,795 | ) | Current | (15,955 | ) | ||||||||||||||||||||
Non-Current | (8,082 | ) | Non-Current | (6,560 | ) | Non-Current | (8,082 | ) | Non-Current | (6,560 | ) | |||||||||||||||||||||
Total gross amounts offset in Balance Sheets | (36,877 | ) | (22,515 | ) | (36,877 | ) | (22,515 | ) | ||||||||||||||||||||||||
Net amounts presented in Balance Sheets | Current | 22,229 | Current | 1,425 | Current | 2,661 | Current | 31,957 | ||||||||||||||||||||||||
Non-Current | 3,898 | Non-Current | 3,035 | Non-Current | 1,358 | Non-Current | 4,306 | |||||||||||||||||||||||||
$ | 26,127 | $ | 4,460 | $ | 4,019 | $ | 36,263 |
The following table presents information about the components of the gain (loss) on derivative instruments (in thousands).
Year Ended June 30, | ||||||||||||
Gain (loss) on derivative financial instruments | 2015 | 2014 (Restated) | 2013 (Restated) | |||||||||
Cash Settlements, net of purchased put premium amortization | $ | 81,049 | $ | (17,312 | ) | $ | (1,417 | ) | ||||
Proceeds from monetizations | 102,354 | — | 760 | |||||||||
Change in fair value | 52,036 | (69,656 | ) | (20,851 | ) | |||||||
Total gain (loss) on derivative financial instruments | $ | 235,439 | $ | (86,968 | ) | $ | (21,508 | ) |
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At June 30, 2015, we had no deposits for collateral with our counterparties.
Note 11 — Stockholders’ Equity
Common Stock
Our common stock trades on the NASDAQ under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.
During fiscal year 2015, we paid to holders of our common stock cash dividends of $0.12 per share on September 12, 2014 and December 12, 2014 and $0.01 per share on March 13, 2015 and June 12, 2015. During fiscal year 2014, we paid to holders of our common stock quarterly cash dividends of $0.12 per share. During fiscal year 2013, we paid to holders of our common stock cash dividends of $0.07 per share on September 14, 2012, December 14, 2012 and March 15, 2013 and $0.12 per share on June 14, 2013.
122
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 11 — Stockholders’ Equity – (continued)
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 on our revolving credit facility. Any repurchased shares of common stock will be retained at our subsidiary level, subject to transfer to the parent company where they may be retired.
Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, during the year ended June 30, 2014, we incurred $94.2 million to repurchase 3,700,463 shares of our common stock at a weighted average price per share, excluding fees, of $25.45 and during the year ended June 30, 2013, we incurred $72.7 million to repurchase 2,938,900 shares of our common stock at a weighted average price per share, excluding fees, of $24.70. As of June 30, 2015, $83.2 million remains available for repurchase under the share repurchase program. We have not made any repurchases under our repurchase program during the fiscal year ended June 30, 2015, and we have suspended the repurchase program indefinitely to reduce our capital needs.
In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, we repurchased 2,776,200 shares of our common stock for approximately $76 million, at a weighted average price per share, excluding fees of $27.39.
In February 2014, we retired 2,087,126 shares of our common stock, resulting in 7,329,100 shares of common stock being held in treasury. On June 3, 2014, we reissued the entire 7,329,100 shares of common stock in treasury as part of our common stock issued to EPL stockholders upon merger.
As discussed in Note 7 — Long-Term Debt of Notes to Consolidated Financial Statements in this Form 10-K, in November 2013, we sold $400 million of 3.0% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3.0% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital.
As discussed in Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in this Form 10-K, upon closing of the EPL Acquisition, we issued 23,320,955 shares of our common stock, including the treasury shares, as noted above, as part of the Merger Consideration.
Preferred Stock
Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our Board of Directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.
Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year.
Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purpose at 95% of the market value of our common stock as determined on the second trading day immediately prior to the record date for such dividend.
123
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 11 — Stockholders’ Equity – (continued)
In the event of a liquidation, winding-up or dissolution of the Company, the 5.625% Preferred Stock and the 7.25% Preferred Stock would receive a liquidation preference of $250 and $100 per share, respectively, plus any accumulated or accrued dividends to be paid out of the assets of the Company available for distribution before any payment is made to the Company’s common stockholders. If the assets of the Company are insufficient to pay the full amounts owed to the holders of the 5.625% Preferred Stock and the 7.25% Preferred Stock, no distributions will be made on account of any shares of stock ranking equally to the 5.625% Preferred Stock and the 7.25% Preferred Stock unless done so equally, ratably and in proportion to the amounts to which all equally ranked holders are entitled.
The 5.625% Preferred Stock is convertible into 9.8353 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 5.625% Preferred Stock Certificate of Designation. At June 30, 2015, the conversion rate was 10.4765 common shares per preferred share. On or after December 15, 2013, we may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common stock equals or exceeds 130% of the then-prevailing conversion price. The 5.625% Preferred Stock became callable beginning December 15, 2013 if our common stock trading price exceeds $32.45 per share for 20 of 30 consecutive trading days.
The 7.25% Preferred Stock is convertible into 8.77192 shares of our common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 7.25% Preferred Stock Certificate of Designation. At June 30, 2015, the conversion rate was 9.3439 common shares per preferred share. On or after December 15, 2014, we may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of our common stock equals or exceeds 150% of the then-prevailing conversion price.
Conversion of Preferred Stock
During the year ended June 30, 2015, we canceled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the year ended June 30, 2015, we also canceled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share.
During the year ended June 30, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share.
During the year ended June 30, 2013, we canceled and converted a total of 929 shares of our 5.625% Preferred Stock into a total of 9,183 shares of common stock using a conversion rate ranging from 9.8578 to 9.899 common shares per preferred share.
Note 12 — Supplemental Cash Flow Information
The following table presents our supplemental cash flow information (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Cash paid for interest | $ | 243,238 | $ | 139,575 | $ | 99,377 | ||||||
Cash paid for income taxes | 933 | 3,641 | 12,873 |
124
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 12 — Supplemental Cash Flow Information – (continued)
The following table presents our non-cash investing and financing activities (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Financing of insurance premiums | $ | — | $ | 21,967 | $ | 22,524 | ||||||
Derivative instruments premium financing | 12,025 | 11,257 | 18,231 | |||||||||
Changes in capital expenditures accrued in accounts payable | (168,569 | ) | 115,696 | 37,274 | ||||||||
Non-cash changes in asset retirement obligations | 49,495 | 299,225 | (9,820 | ) | ||||||||
Repurchase of Company common stock | — | — | 13,997 | |||||||||
Treasury stock reissued for the EPL Acquisition | — | 154,717 | — | |||||||||
Common stock issued for the EPL Acquisition | — | 337,588 | — |
Note 13 — Employee Benefit Plans
The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We maintain an incentive and retention program for our employees. Participation shares (or “Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. These are liability awards and are marked to market at the end of each reporting period. The Restricted Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Restricted Stock Units.
Performance Units
Units issued through Fiscal Year 2014. For fiscal 2014 and 2013, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period. These are liability awards and are marked to market at the end of each reporting period.
Time-Based Performance Units. The amount due the employee at the vesting date is equal to the grant date unit value of $5.00 times the percentage increase in the stock price over the performance period, multiplied by the number of units that vest. If the stock price declines over the performance period, the amount due the employee at the vesting date is equal to the grant date unit value of $5.00, multiplied by the number of units that vest. For the fiscal year 2013 and 2014 grants, the initial stock prices were $24.50, and $22.48, respectively.
TSR Performance-Based Units. For fiscal 2014 and 2013 TSR Performance-Based Units, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage increase in the price per share of our common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier. If the stock price declines over the performance period, the amount due the executive at the vesting date is equal to the grant date unit value of $5.00, multiplied by the TSR Unit Number Modifier. In addition, the employee may have the opportunity to earn additional compensation based on our Total Shareholder Return at the end of the third performance period for the 2014 and 2013 grants. Such additional compensation will apply if the TSR Unit Number Modifier is higher at the end of the third performance period than it was at the two prior vesting dates.
At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash. The July 2015 vesting of the July 2014, 2013, and 2012 Performance Unit awards were also settled in cash; however, future vesting of the Performance Units may be settled in common stock
125
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 13 — Employee Benefit Plans – (continued)
at the discretion of our Board of Directors. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.
Changes for Fiscal 2015 Performance Unit Grants. For the performance unit awards granted in fiscal 2015, the Remuneration Committee of the Board of Directors changed the performance measure within the Incentive Plan from absolute TSR to relative TSR compared to a performance peer group. Under this plan, executives will receive no payout for TSR performance below the 25th percentile, a 50% payout for TSR performance at the 25th percentile, a 100% payout for TSR performance at the median, and 200% payout for performance at or above the 75th percentile. Payouts under this plan are capped at a target if absolute total shareholder return is negative. In addition, the Remuneration Committee decided to eliminate the use of a $5 notional unit and instead will denominate units based on the stock price on the grant date. The Remuneration Committee also decided to eliminate the make-up feature for the fiscal 2015 awards. The make-up feature provided for additional compensation at the end of the third performance period if the TSR Unit Number Modifier was higher at the end of the third performance period than it was at the two prior vesting dates. The awards for fiscal 2015 have continued to be granted 25% in the form of Time-Based Performance Unit awards and 75% in the form of TSR Performance-Based Unit awards.
The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units.
We recognized compensation expense related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Restricted Stock Units | $ | 8,631 | $ | 12,798 | $ | 10,707 | ||||||
Performance Units | (4,692 | ) | 11,446 | 10,569 | ||||||||
Total compensation expense recognized | $ | 3,939 | $ | 24,244 | $ | 21,276 |
As of June 30, 2015, we had 4,302,398 unvested Restricted Stock Units, 2,361,250 unvested Performance Based Units and 781,000 TSR Performance Based Units.
Non-Executive Director Compensation. On November 7, 2011, the Remuneration Committee approved the director compensation program which provides for an annual stock award of $175,000 worth of shares. The equity retainer is paid in our common stock in an amount equivalent to $175,000 using our closing stock price on the date of the Annual General Meeting, which represents the grant date fair value computed in accordance with ASC Topic 718. For the fiscal year 2015, each director (except our two recently appointed directors) was awarded 26,396 shares of common stock based on a $6.63 closing price on the date of the 2014 Annual General Meeting. Our two recently appointed directors were awarded a pro-rated amount based on their service as directors beginning on December 15, 2014, which awards totaled 63,406 shares of common stock each based on a $2.45 closing price on the date of appointment of December 15, 2014. The shares will vest on the date of the 2015 Annual General Meeting. See Note 14 — “Related Party Transactions” for information regarding Restricted Stock Units and consulting fees paid to one of the recently appointed directors for his services as our Interim Chief Strategic Officer.
126
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 13 — Employee Benefit Plans – (continued)
Stock Purchase Plan
Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or are newly issued by us at the then current market price per share. During the years ended June 30, 2015, 2014, and 2013, we issued 180,323 shares, 148,519 shares, and 213,763 shares, respectively, under the 2008 Purchase Plan.
In November 2008, we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from July 1, 2015 to December 31, 2015. We use the Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under the Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of June 30, 2015 there was no unrecognized compensation expense. The compensation expense recognized and shares issued under the Employee Stock Purchase Plan were as follows (in thousands,except for shares):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Compensation expense | $ | 785 | $ | 866 | $ | 813 | ||||||
Shares issued | 365,541 | 92,297 | 74,806 |
Stock Options
In September 2008, our Board of Directors granted 300,000 stock options to certain officers of the Company. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. We utilized the Black-Scholes model to determine the fair value of these stock options upon issuance. During the year ended June 30, 2015, 50,000 of these stock options were forfeited and 150,000 remain outstanding. As of June 30, 2015 there was no unrecognized compensation expense.
Defined Contribution Plans
Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Profit Sharing Plan | $ | (768 | ) | $ | 4,833 | $ | 2,738 | |||||
401(k) Plan | 3,192 | 3,395 | 3,381 | |||||||||
Total contributions | $ | 2,424 | $ | 8,228 | $ | 6,119 |
127
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 14 — Related Party Transactions
At June 30, 2015, we had a 20% interest in EXXI M21K and accounted for this investment using the equity method. On August 11, 2015, we acquired all of the equity interests of M21K. See Note 6 — “Equity Method Investments” and Note 21 — “Subsequent Events.”
We had provided a guarantee related to the payment of asset retirement obligations and other liabilities assumed by M21K in the EP Energy property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations assumed by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchased, we guaranteed payment of asset retirement obligations assumed by M21K estimated at $18.6 million. For these guarantees, M21K agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the years ended June 30, 2015, 2014 and 2013, we received $3.7 million, $3.1 million and $1.9 million, respectively, related to such guarantees.
Prior to the LLOG Exploration acquisition, we received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties were purchased on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the years ended June 30, 2015, 2014 and 2013, we received management fees of $3.3 million, $3.8 million and $1.7 million, respectively.
On April 1, 2014, we sold our interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K. See Note 3 — “Acquisitions and Dispositions.”
In order to enhance our ability to pursue alternative financing structures, our Board of Directors appointed one of its members, James LaChance, to serve as our interim Chief Strategic Officer. In that position, Mr. LaChance has pursued discussions with our lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by our Chief Executive Officer, in consultation with the Board. In light of the significant increase in the amount of time Mr. LaChance is required to spend performing in this new role, on February 23, 2015, we and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance was paid $200,000 per month for his services as interim Chief Strategic Officer. For year ended June 30, 2015, we paid Mr. LaChance consulting fees of $1.1 million under the Consulting Agreement.
In accordance with the Consulting Agreement and based on certain objective criteria as set forth therein, Mr. LaChance received a success fee in connection with the issuance of the 11.0% Notes. In accordance with the terms of the Consulting Agreement, fifty percent of the success fee was required to be paid to Mr. LaChance in the form of cash-settled restricted stock units (“RSUs”), and Mr. LaChance elected to receive the remaining 50% of the success fee in the form of RSUs on the same terms, subject to certain limitations. On March 12, 2015, based on a price of $3.04 per share, which is the value weighted average price of our common stock for the period from December 1, 2014 through January 31, 2015 as defined by the Consulting Agreement, Mr. LaChance was awarded 1,644,737 RSUs. Based on the closing stock price of $3.24 on March 12, 2015, the fair value of these RSUs was $5.3 million, which amount reflects the number of restricted stock units (“RSUs”) awarded. As set forth in the Consulting Agreement, these RSUs will generally be settled in cash on the 12-month anniversary of the issuance of the 11.0% Notes. These RSUs will be settled earlier if, prior to that 12-month anniversary, a change of control occurs or, subject to certain limitations, if Mr. LaChance is no longer serving on the Board of Directors. On the RSU settlement date, Mr. LaChance will have the option to receive all or part of his RSU cash settlement in shares of our common stock, valued at the closing price on the settlement date.
128
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 14 — Related Party Transactions – (continued)
The term of the Consulting Agreement is six months unless terminated earlier upon 30 days’ notice by either party or upon the closing of financing transactions, and may be extended by mutual agreement. The Consulting Agreement was not extended and expired on July 15, 2015. Mr. LaChance’s duties as interim Chief Strategic Officer were separate from, and in addition to, his responsibilities as a member of the Board of Directors.
The Board has recently learned that the Company’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provided services to the Company totaling $34.7 million, $38.7 million and $38.9 million during the years ended June 30, 2015, 2014 and 2013, respectively. The Board also learned that Norman Louie, one of our directors, made a personal loan to the Chief Executive Officer in 2014 at a time prior to when Mr. Louie became a director of the Company. At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of June 30, 2015, owned a majority interest in Energy XXI M21K.
Note 15 — Earnings (Loss) per Share
Basic earnings (loss) per share of common stock is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, convertible notes, restricted stock and other potential common stock. The following table sets forth the calculation of basic and diluted earnings (loss) per share (“EPS”) (in thousands, except per share data):
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Net income (loss) | $ | (2,433,838 | ) | $ | 18,125 | $ | 180,783 | |||||
Preferred stock dividends | 11,468 | 11,489 | 11,496 | |||||||||
Net income (loss) attributable to common stockholders | $ | (2,445,306 | ) | $ | 6,636 | $ | 169,287 | |||||
Weighted average shares outstanding for basic EPS | 94,167 | 74,375 | 79,063 | |||||||||
Add dilutive securities | — | 70 | 8,200 | |||||||||
Weighted average shares outstanding for diluted EPS | 94,167 | 74,445 | 87,263 | |||||||||
Earnings (loss) per share | ||||||||||||
Basic | $ | (25.97 | ) | $ | 0.09 | $ | 2.14 | |||||
Diluted | $ | (25.97 | ) | $ | 0.09 | $ | 1.94 |
For the years ended June 30, 2015, 2014 and 2013, 8,642,434, 8,336,700, and 5,474 shares of potential common stock, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.
Note 16 — Commitments and Contingencies
Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.
Lease Commitments. We have non-cancelable operating leases for office space and other assets that expire through December 31, 2022. In addition, on June 30, 2015, we entered into an operating lease agreement for the Grand Isle Gathering System as further described below. As of June 30, 2015, future minimum lease commitments under our operating leases are as follows (in thousands):
129
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 16 — Commitments and Contingencies – (continued)
Year Ending June 30, | ||||
2016 | $ | 35,978 | ||
2017 | 38,044 | |||
2018 | 38,432 | |||
2019 | 38,607 | |||
2020 | 42,670 | |||
Thereafter | 284,533 | |||
Total | $ | 478,264 |
For the years ended June 30, 2015, 2014 and 2013, rent expense, including rent incurred on short-term leases, was approximately $6.4 million, $3.7 million, and $2.8 million, respectively.
On June 30, 2015, in connection with the closing of the sale of the Grand Isle Gathering System, we entered into a triple-net lease (the “GIGS Lease”) with Grand Isle Corridor pursuant to which we will continue to operate the Grand Isle Gathering System. The primary term of the GIGS Lease is 11 years from the closing of the sale, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues we realize from the Grand Isle Gathering System above a predetermined oil revenue threshold. During the initial term, we will make fixed minimum monthly rental payments, which vary over the term of the lease. The aggregate annual minimum monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease. Under the terms of the GIGS Lease, we retain any revenues generated from transporting third party volumes.
Under the terms of the GIGS Lease, we control the operation, maintenance, management and regulatory compliance associated with the Grand Isle Gathering System, and we are responsible for, among other matters, maintaining the system in good operating condition, paying all utilities, insuring the assets, repairing the system in the event of any casualty loss, paying property and similar taxes associated with the system, and ensuring compliance with all environmental and other regulatory laws, rules and regulations. The GIGS Lease also imposes certain obligations on Grand Isle Corridor, including confidentiality of information and keeping the Grand Isle Gathering System free of certain liens. In addition, we have, under certain circumstances, a right of first refusal during the term of the GIGS Lease and for two years thereafter to match any proposed transfer by Grand Isle Corridor of its interest as lessor under the GIGS Lease or its interest in the Grand Isle Gathering System.
Letters of Credit and Performance Bonds. As of June 30, 2015, we had $226 million in letters of credit and $319.2 million of performance bonds outstanding. As a lessee and operator of oil and natural gas leases on the federal Outer Continental Shelf (OCS), approximately $157.5 million of our performance bonds are lease and/or area bonds issued to the BOEM that assure our commitment to comply with the terms and conditions of those leases. We also maintain approximately $161.7 million in performance bonds issued to predecessor third party assignors including certain state regulatory bodies of certain of the wells and facilities on these leases pursuant to a contractual commitment made by us to those third parties at the time of assignment with respect to the eventual decommissioning of those wells and facilities. In April 2015, we received letters from the BOEM stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide approximately $1.0 billion in supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements. In June 2015, we reached agreements with the BOEM pursuant to which we provided $150 million of supplemental bonds issued to the BOEM, and the BOEM agreed to withdraw its orders with regard to supplemental bonding and postpone until November 15, 2015 the issuance of further
130
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 16 — Commitments and Contingencies – (continued)
requirements of us related to these supplemental bonding obligations. On June 30, 2015, we sold the East Bay field and the $1.0 billion of requested supplemental bonding was reduced by approximately $178 million.
In connection with the acquisition of the equity interests of M21K in August 2015 as described in Note 21 — “Subsequent Events,” we increased our performance bonds issued to the BOEM by $60.4 million.
Guarantee. EXXI M21K was the guarantor of a $100 million line of credit entered into by M21K. On August 11, 2015, pursuant to a stock purchase agreement between EXXI M21K and EXXI GOM (the “M21K Purchase Agreement”), we acquired all of the equity interests of M21K, LLC. See Note 21 — “Subsequent Events.”
Drilling Rig Commitments. The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of June 30, 2015, we had the following three drilling rig commitments:
1) | $47,000 per day through September 7, 2015, plus minimum commitment fee of $3.6 million, |
2) | $37,000 per day through August 11, 2015, and |
3) | $70,000 per day through August 14, 2015. |
At June 30, 2015, future minimum commitments under these contracts totaled $11.5 million.
Other. We maintain restricted escrow funds as required by certain contractual arrangements. At June 30, 2015, our restricted cash included $10 million in cash collateral associated with our bonding requirements, $5 million related to the GIGS transaction, $21 million related to the East Bay sale which will remain restricted until our next borrowing base redetermination and approximately $6 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field which will be transferred to the buyer of our interests in that field.
We and our oil and gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and the related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material.
Note 17 — Income Taxes
We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure.
In connection with preparing this Form 10-K, we restated our previously issued consolidated financial statements including restatement of our deferred tax balances (see further discussion at Note 22 — “Restatement of Previously Issued Consolidated Financial Statements”). The restatement did not require us to amend any previous income tax filings as the changes in the financial accounting method for derivatives and the resulting effect on depletion, depreciation, and amortization had no effect on our taxable income (loss) as determined for any year. Deferred tax balances related to the changes in balance sheet carrying amounts for derivative instruments and oil and gas properties were revised as required by the adjustments to pre-tax book income.
131
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 17 — Income Taxes – (continued)
Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and EGC will not file a combined nor consolidated Louisiana income tax return. Our valuation allowance of $23.8 million at June 30, 2014 related to Energy XXI’s separate company Louisiana net operating loss (“NOL”) carryovers that we did not believe, on a more likely-than-not basis, would be realized in future years due to the focus on offshore operations. During fiscal year 2015, there were two changes in judgement affecting the amount of the valuation allowance. In the third quarter of fiscal year 2015, an intercompany transaction related to the sale of the GIGS generated current year Louisiana-only taxable income during fiscal year 2015 resulting in the release of $1.8 million of the previously recorded Louisiana valuation allowance. Subsequently, changes in our expectations regarding our future taxable income, consistent with net losses recorded during the current fiscal year (that are heavily influenced by oil and gas property impairments), caused us to record a net increase in our valuation allowance of $356.8 million resulting in a balance of $379.3 million at June 30, 2015. We recorded this increase to our valuation allowance against our net deferred tax assets due to our judgment that our existing U.S. federal and State of Louisiana NOL carryforwards are not, on a more-likely-than-not basis, likely recoverable in future years. We continue to evaluate the need for the valuation allowance based on current and expected earnings and other factors, and adjust it accordingly.
Our income (loss) before income taxes attributable to U.S. and non-U.S. operations are as follows (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
U.S. income (loss) | $ | (3,050,659 | ) | $ | 43,915 | $ | 188,000 | |||||
Non-U.S. income | 3,471 | 9,230 | 25,377 | |||||||||
Income (loss) before income taxes | $ | (3,047,188 | ) | $ | 53,145 | $ | 213,377 |
The components of our income tax expense (benefit) are as follows (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Current | ||||||||||||
U.S. | $ | 933 | $ | 3,641 | $ | 12,872 | ||||||
Non U.S. | — | — | — | |||||||||
State | 99 | — | — | |||||||||
Total current | 1,032 | 3,641 | 12,872 | |||||||||
Deferred | ||||||||||||
U.S. | (564,569 | ) | 31,379 | 22,183 | ||||||||
State | (49,813 | ) | — | (2,461 | ) | |||||||
Total deferred | (614,382 | ) | 31,379 | 19,722 | ||||||||
Total income tax expense (benefit) | $ | (613,350 | ) | $ | 35,020 | $ | 32,594 |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 17 — Income Taxes – (continued)
The following is a reconciliation of statutory income tax expense to our income tax provision (benefit) (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Income (loss) before income taxes | $ | (3,047,188 | ) | $ | 53,145 | $ | 213,377 | |||||
Statutory rate | 35 | % | 35 | % | 35 | % | ||||||
Income tax expense (benefit) computed at statutory rate | (1,066,516 | ) | 18,601 | 74,682 | ||||||||
Reconciling items | ||||||||||||
Federal withholding obligation | 10,331 | 10,343 | 10,343 | |||||||||
Nontaxable foreign income | 91 | (2,133 | ) | (8,214 | ) | |||||||
Change in valuation allowance | 356,798 | — | (101,524 | ) | ||||||||
Tax return to provision adjustment to oil and natural gas properties | — | — | 52,072 | |||||||||
State income taxes (benefit), net of federal tax benefit | (32,314 | ) | — | (2,461 | ) | |||||||
Non-deductible executive compensation | — | 2,725 | 5,616 | |||||||||
Non-deductible transaction costs | 440 | 1,853 | — | |||||||||
Goodwill impairment | 115,253 | |||||||||||
Other – Net | 2,567 | 3,631 | 2,080 | |||||||||
Income tax expense (benefit) | $ | (613,350 | ) | $ | 35,020 | $ | 32,594 |
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of our deferred taxes are detailed in the table below (in thousands):
June 30, | ||||||||
2015 | 2014 (Restated) | |||||||
Deferred tax assets – current | ||||||||
Asset retirement obligation | $ | 11,650 | $ | 44,182 | ||||
Other | 7,140 | 8,405 | ||||||
Total deferred tax assets – current | 18,790 | 52,587 | ||||||
Deferred tax liabilities – current | ||||||||
Dismantlement | (9,086 | ) | — | |||||
Total deferred tax liabilities – current | (9,086 | ) | — | |||||
Valuation allowance | (9,704 | ) | — | |||||
Deferred tax assets – non current | ||||||||
Asset retirement obligation | 158,830 | 61,412 | ||||||
Tax loss carryforwards on U.S. operations | 458,530 | 448,404 | ||||||
Accrued interest expense | 106,039 | 79,636 | ||||||
Deferred state taxes | 54,973 | 22,494 | ||||||
Derivative instruments and other | 4,879 | 12,163 | ||||||
Other | 7,711 | 11,471 | ||||||
Total deferred tax assets – non current | 790,962 | 635,580 | ||||||
Deferred tax liabilities |
133
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 17 — Income Taxes – (continued)
June 30, | ||||||||
2015 | 2014 (Restated) | |||||||
Oil, natural gas properties and other property and equipment | (272,502 | ) | (1,149,795 | ) | ||||
Federal withholding obligation | (73,474 | ) | (63,143 | ) | ||||
Cancellation of debt | (9,680 | ) | (9,680 | ) | ||||
Employee benefit plans | (9,588 | ) | (3,611 | ) | ||||
Tax partnership activity | (56,130 | ) | (53,826 | ) | ||||
Total deferred tax liabilities – non current | (421,374 | ) | (1,280,055 | ) | ||||
Valuation allowance | (369,588 | ) | (22,494 | ) | ||||
Net deferred tax liability | $ | — | $ | (614,382 | ) | |||
Reflected in the accompanying balance sheet as | ||||||||
Current deferred tax asset | $ | — | $ | 52,587 | ||||
Non-current deferred tax liability | $ | — | $ | (666,969 | ) |
The total change in deferred tax assets and liabilities in the year ended June 30, 2015 reflects a $648.5 million decrease in the net deferred tax liability due to a significant pre-tax operating loss recorded for fiscal year 2015 (that was heavily influenced by goodwill and property impairments).
At June 30, 2015, we have a U.S. federal tax loss carryforward (“NOLs”) of approximately $1.5 billion, and state income tax loss carryforwards of approximately $800 million, including amounts carried into the Company’s U.S. group from the EPL acquisition. The regular U.S. federal income tax NOLs will expire in various amounts beginning in 2026 and ending in 2035.
Section 382 of the Code (“Section 382”) imposes limitations on a corporation’s ability to utilize its NOLs if it experiences an “ownership change” and Code Section 383 provides similar rules for other tax attributes, e.g., capital losses. In general terms, an ownership change may result from transactions increasing the ownership percentage of certain shareholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of the NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax exempt rate (ranging between approximately 3.27% and 2.5%). Any unused annual limitation may be carried over to subsequent years. The amount of the limitation may, under certain circumstances, be increased by the built-in gains held by the Company at the time of the ownership change that are recognized in the five year period after the change. At June 30, 2015, we estimate $800 million in NOL usage is available under this “recognized built-in gain” exception. This amount coupled with the annual limitation amount (heavily influenced by existing stock price) is insufficient to fully utilize NOLs recorded to date; thus requiring us to record a valuation allowance during the year. We experienced an ownership change on June 20, 2008, and a second ownership change on November 3, 2010. EPL similarly experienced an ownership change in 2009 and upon its acquisition in 2014. Management will continue to monitor the potential impact of Code Sections 382 and 383 in future periods with respect to NOL and other tax carryforwards and will reassess realization of these carryforwards periodically.
We have not recorded any reserves for uncertain tax positions. At June 30, 2015, we have a gross unrecorded noncurrent deferred tax asset of $13.2 million representing a percentage depletion carryover resulting from the EPL acquisition.
We filed our initial tax returns for the tax year ended June 30, 2006 as well as the returns for the tax years ended June 30, 2007 through 2014. The statute of limitations for examination of NOLs and other similar attribute carryforwards does not begin to run until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under U.S. federal tax law. On January 12, 2015, the U.S. Internal Revenue Service formally notified us that they had completed their examination of our
134
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 17 — Income Taxes – (continued)
U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward.
We have historically paid no significant U.S. cash income taxes due to the election to expense intangible drilling costs and the presence of our NOLs. However, if current income trends continue, we could be responsible for making cash tax payments in fiscal 2016 from application of the alternative minimum tax (AMT) under current law. We presently do not expect to make any cash income tax payments during the upcoming fiscal year. If any such AMT payments were required, we believe that they would be recoverable against future regular income taxes due, with no expiration period. As such, we do not believe that any cash AMT payments would have a negative impact on earnings. We revise our ongoing estimated AMT obligation each quarter during the year.
We paid $0.9 million and $3.6 million cash in U.S. withholding taxes during the years ended June 30, 2015 and 2014, respectively, as a result of payments of interest on indebtedness and management fees to our Bermuda entities. These withholding taxes are presented as separate line items in the effective tax rate reconciliation and payments expected in the coming fiscal year are presented as a current federal withholding obligation in the balance sheet.
Note 18 — Concentrations of Credit Risk
Major 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 natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market-based prices.
Shell Trading Company (“Shell”) accounted for approximately 29%, 45%, and 35% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014, and 2013, respectively. ExxonMobil Corporation (“ExxonMobil”) accounted for approximately 26%, 43%, and 37% of our total oil and natural gas revenues during the years ended June 30, 2015, 2014, and 2013, respectively. Chevron USA (“Chevron”) accounted for approximately 24% of our total oil and natural gas revenues during the year ended June 30, 2015. J.P. Morgan Ventures Energy Corporation accounted for 12% of our total oil and natural gas revenues during the year ended June 30, 2013. 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, ExxonMobil or Chevron curtailed their purchases.
Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales and joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions.
Derivative Instruments. Derivative instruments also expose us to credit risk in the event of nonperformance by counterparties. Generally, these contracts are with major investment grade financial institutions and other substantive counterparties. We believe that our credit risk related to the futures and swap contracts is no greater than the risk associated with the contracts they hedge and that the mitigation of price risk through our hedging activities reduces volatility in our financial position and cash flows from period to period and lowers our overall business risk.
Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents with major high credit quality financial institutions. At times cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 18 — Concentrations of Credit Risk – (continued)
Geographic Concentration. Virtually all of our current operations and proved reserves are concentrated in the Gulf of Mexico region. Therefore, we are exposed to operational, regulatory and other risks associated with the Gulf of Mexico, including the risk of adverse weather conditions. We maintain insurance coverage against some, but not all, of the operating risks to which our business is exposed.
Note 19 — Fair Value of Financial Instruments
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
• | Level 1 — quoted prices in active markets for identical assets or liabilities. |
• | Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). |
• | Level 3 — unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. |
For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the revolving credit facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.
Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 10 — “Derivative Financial Instruments.”
The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 19 — Fair Value of Financial Instruments – (continued)
During the year ended June 30, 2015, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):
Level 1 | Level 2 | |||||||||||||||
As of June 30, 2015 | As of June 30, 2014 | As of June 30, 2015 | As of June 30, 2014 | |||||||||||||
Assets: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 63,004 | $ | 26,975 | ||||||||
Liabilities: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 40,896 | $ | 58,778 | ||||||||
Restricted stock units | 6,325 | 9,425 | — | — | ||||||||||||
Time-based performance units | 1,978 | 3,698 | — | — | ||||||||||||
Total liabilities | $ | 8,303 | $ | 13,123 | $ | 40,896 | $ | 58,778 |
The following table sets forth the carrying values and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments (in thousands):
June 30, 2015 | June 30, 2014 | |||||||||||||||
Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | |||||||||||||
Revolving credit facility | $ | 150,000 | $ | 150,000 | $ | 689,000 | $ | 689,000 | ||||||||
11% Senior Secured Second Lien Notes due 2020 | 1,398,896 | 1,276,000 | — | — | ||||||||||||
8.25% Senior Notes due 2018 | 539,459 | 306,000 | 550,566 | 545,700 | ||||||||||||
6.875% Senior Notes due 2024 | 650,000 | 211,250 | 650,000 | 663,000 | ||||||||||||
3.0% Senior Convertible Notes due 2018 | 354,218 | 94,000 | 342,986 | 396,780 | ||||||||||||
7.5% Senior Notes due 2021 | 500,000 | 164,925 | 500,000 | 541,250 | ||||||||||||
7.75% Senior Notes due 2019 | 250,000 | 92,135 | 250,000 | 269,480 | ||||||||||||
9.25% Senior Notes due 2017 | 750,000 | 413,160 | 750,000 | 806,630 | ||||||||||||
$ | 4,592,573 | $ | 2,707,470 | $ | 3,732,552 | $ | 3,911,840 |
The 11.0% Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings. Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at June 30, 2015 are not material.
The following table sets forth our Level 3 financial instruments (in thousands):
Level 3 | ||||||||
Year Ended June 30, | ||||||||
2015 | 2014 | |||||||
Liabilities: | ||||||||
Performance-based performance units | ||||||||
Balance at beginning of period | $ | 6,910 | $ | 6,778 | ||||
Vested | — | (7,188 | ) | |||||
Grants charged to general and administrative expense | (6,877 | ) | 7,320 | |||||
Balance at end of period | $ | 33 | $ | 6,910 |
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 20 — Prepayments and Accrued Liabilities
Prepayments and accrued liabilities consist of the following (in thousands):
June 30, | ||||||||
2015 | 2014 | |||||||
Prepaid expenses and other current assets | ||||||||
Advances to joint interest partners | $ | 1,294 | $ | 10,336 | ||||
Insurance | 3,427 | 37,088 | ||||||
Inventory | 7,867 | 7,020 | ||||||
Royalty deposit | 3,137 | 12,262 | ||||||
Other | 8,573 | 5,824 | ||||||
Total prepaid expenses and other current assets | $ | 24,298 | $ | 72,530 | ||||
Accrued liabilities | ||||||||
Advances from joint interest partners | 3,060 | 2,667 | ||||||
Employee benefits and payroll | 18,927 | 43,480 | ||||||
Interest payable | 83,384 | 26,490 | ||||||
Accrued hedge payable | 1,399 | 7,874 | ||||||
Undistributed oil and gas proceeds | 19,776 | 34,473 | ||||||
Severance taxes payable | 843 | 8,014 | ||||||
Other | 27,917 | 10,528 | ||||||
Total accrued liabilities | $ | 155,306 | $ | 133,526 |
Note 21 — Subsequent Events
During July through September 2015, we repurchased approximately $253.7 million, $50.4 million and $123.7 million in aggregate principal amount of the 7.5% Senior Notes, the 6.875% Senior Notes and the 7.75% Senior Notes, respectively, in open market transactions at a total price of approximately $94.4 million. In the quarter ended September 30, 2015, we will record a gain on the repurchase of approximately $333.4 million less the amount of associated debt issue costs and the notes will be cancelled.
On August 11, 2015, pursuant to the M21K Purchase Agreement, we acquired all of the remaining equity interests of M21K, LLC for consideration consisting of the assumption of all obligations and liabilities of M21K including approximately $25.2 million associated with M21K’s first lien credit facility, which was required to be paid at closing. The sellers retained certain overriding royalty interests applicable only to the extent that production proceeds during any calendar month average in excess of $65.00/Bbl WTI and $3.50/MMbtu Henry Hub and limited to a term of four years or an aggregate amount of $20 million, whichever occurs earlier. In addition, with respect to the Eugene Island 330 and South Marsh Island 128 fields, in the event we sell our interest in one or both of these fields, the overriding royalty interests with respect to such sold field shall terminate; provided, however if such sale occurs within four years of the effective date of the M21K Purchase Agreement and the consideration received for such sale is greater than the allocated value for such field as specified in the M21K Purchase Agreement, then we are obligated to pay an amount equal to 20% of the portion of the consideration received in excess of the specified allocated value of such field. Prior to this transaction which is effective as of August 1, 2015, we had owned a 20% interest in M21K through our investment in EXXI M21K. See Note 6 — “Equity Method Investments”.
On August 13, 2015, we sold our interest in a pipeline originating at East Cameron Block 338 and terminating at Vermillion Block 265 for $4.2 million in cash plus assumption of abandonment costs and certain repairs.
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ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 22 — Restatement of Previously Issued Consolidated Financial Statements
Prior to the issuance of this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.
The effects of the restatement on our consolidated financial statements are summarized below:
• | Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and |
• | Resulting adjustments required to deferred income taxes and income tax expense (benefit). |
While these non-cash reclassifications impact revenues, net income (loss) in each period, net income (loss) attributable to common stockholders, and net income (loss) per common share, as well as total stockholders’ equity, they have no material impact on cash flows. See additional disclosures of the effects of the restatement within Notes 3, 5, 15, 17 and 25. Details of the impact of the restatement on stockholders’ equity as of June 30, 2012, on the balance sheet as of June 30, 2014 and on the statements of operations for the years ended June 30, 2014 and 2013 are as follows:
As of June 30, 2012 | ||||||||||||
As Reported | Adjustment | Restated | ||||||||||
(In thousands) | ||||||||||||
Preferred Stock | $ | 1 | $ | — | $ | 1 | ||||||
Common Stock | 396 | — | 396 | |||||||||
Paid-In Capital | 1,501,785 | — | 1,501,785 | |||||||||
Accumulated deficit | (153,945 | ) | (61,461 | ) | (215,406 | ) | ||||||
Accumulated Other Comprehensive Income (Loss) | 57,603 | (57,603 | ) | — | ||||||||
Total Stockholders’ Equity | $ | 1,405,840 | $ | (119,064 | ) | $ | 1,286,776 |
139
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 22 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
The adjustment to accumulated deficit is comprised of the following cumulative effects (in thousands):
Change in accounting for derivative financial instruments | $ | 88,656 | ||
Related impact on ceiling test impairment | (187,800 | ) | ||
Related impact on depreciation, depletion and amortization | 68,736 | |||
Total pre-tax adjustments | (30,408 | ) | ||
Related income tax provision (benefit) | 31,053 | |||
Net after-tax adjustments | $ | (61,461 | ) |
As of June 30, 2014 | ||||||||||||
As Reported | Adjustment | Restated | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Total Current Assets | $ | 457,759 | — | 457,759 | ||||||||
Property and Equipment | ||||||||||||
Oil and natural gas properties, net | 6,524,602 | (97,339 | ) | 6,427,263 | ||||||||
Other property and equipment | 19,760 | — | 19,760 | |||||||||
Total Property and Equipment, net | 6,544,362 | (97,339 | ) | 6,447,023 | ||||||||
Total Other Assets | 436,715 | — | 436,715 | |||||||||
Total Assets | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 | |||||
Total Current Liabilities | $ | 699,895 | — | 699,895 | ||||||||
Deferred Income Taxes | 701,038 | (34,069 | ) | 666,969 | ||||||||
Other Non-Current Liabilities | 4,240,073 | — | 4,240,073 | |||||||||
Total Liabilities | 5,641,006 | (34,069 | ) | 5,606,937 | ||||||||
Stockholders’ Equity | ||||||||||||
Preferred stock | 1 | — | 1 | |||||||||
Common stock | 468 | — | 468 | |||||||||
Additional paid-in capital | 1,837,462 | — | 1,837,462 | |||||||||
Accumulated deficit | (19,626 | ) | (83,745 | ) | (103,371 | ) | ||||||
Accumulated other comprehensive loss, net of income taxes | (20,475 | ) | 20,475 | — | ||||||||
Total Stockholders’ Equity | 1,797,830 | (63,270 | ) | 1,734,560 | ||||||||
Total Liabilities and Stockholders’ Equity | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 |
140
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 22 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Year Ended June 30, 2014 | ||||||||||||
As Reported | Adjustment | Restated | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Revenues | ||||||||||||
Crude oil sales | $ | 1,091,223 | $ | 12,985 | $ | 1,104,208 | ||||||
Natural gas sales | 139,502 | (3,619 | ) | 135,883 | ||||||||
Gain (loss) on derivative financial instruments | — | (86,968 | ) | (86,968 | ) | |||||||
Total Revenues | 1,230,725 | (77,602 | ) | 1,153,123 | ||||||||
Costs and Expenses | ||||||||||||
Depreciation, depletion and amortization | 423,319 | (9,293 | ) | �� | 414,026 | |||||||
Loss on derivative financial instruments | 5,704 | (5,704 | ) | — | ||||||||
All other costs and expenses | 521,291 | — | 521,291 | |||||||||
Total Costs and Expenses | 950,314 | (14,997 | ) | 935,317 | ||||||||
Operating Income | 280,411 | (62,605 | ) | 217,806 | ||||||||
Other Income (Expense) | ||||||||||||
Loss from equity method investees | (4,781 | ) | (450 | ) | (5,231 | ) | ||||||
Other income, net | 3,298 | — | 3,298 | |||||||||
Interest expense | (162,728 | ) | — | (162,728 | ) | |||||||
Total Other Expense, net | (164,211 | ) | (450 | ) | (164,661 | ) | ||||||
Income Before Income Taxes | 116,200 | (63,055 | ) | 53,145 | ||||||||
Income Tax Expense | 57,089 | (22,069 | ) | 35,020 | ||||||||
Net Income | 59,111 | (40,986 | ) | 18,125 | ||||||||
Preferred Stock Dividends | 11,489 | — | 11,489 | |||||||||
Net Income Available for Common Stockholders | $ | 47,622 | $ | (40,986 | ) | $ | 6,636 | |||||
Earnings per Share | ||||||||||||
Basic | $ | 0.64 | $ | 0.09 | ||||||||
Diluted | $ | 0.64 | $ | 0.09 | ||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||
Basic | 74,375 | 74,375 | ||||||||||
Diluted | 74,445 | 74,445 | ||||||||||
Net Income | $ | 59,111 | $ | (40,986 | ) | $ | 18,125 | |||||
Other Comprehensive Loss | ||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||
Unrealized change in fair value net of ineffective portion | (62,133 | ) | 62,133 | — | ||||||||
Effective portion reclassified to earnings during the period | (10,215 | ) | 10,215 | — | ||||||||
Total Other Comprehensive Loss | (72,348 | ) | 72,348 | — | ||||||||
Income Tax Benefit | (25,321 | ) | 25,321 | — | ||||||||
Net Other Comprehensive Loss | (47,027 | ) | 47,027 | — | ||||||||
Comprehensive Income | $ | 12,084 | $ | 6,041 | $ | 18,125 |
141
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 22 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Year Ended June 30, 2013 | ||||||||||||
As Reported | Adjustment | Restated | ||||||||||
(In thousands, except per share amounts) | ||||||||||||
Revenues | ||||||||||||
Crude oil sales | $ | 1,080,982 | $ | (13,295 | ) | $ | 1,067,687 | |||||
Natural gas sales | 127,863 | (15,110 | ) | 112,753 | ||||||||
Gain (loss) on derivative financial instruments | — | (21,508 | ) | (21,508 | ) | |||||||
Total Revenues | 1,208,845 | (49,913 | ) | 1,158,932 | ||||||||
Costs and Expenses | ||||||||||||
Depreciation, depletion and amortization | 376,224 | (12,433 | ) | 363,791 | ||||||||
Loss on derivative financial instruments | 1,756 | (1,756 | ) | — | ||||||||
All other costs and expenses | 469,060 | — | 469,060 | |||||||||
Total Costs and Expenses | 847,040 | (14,189 | ) | 832,851 | ||||||||
Operating Income | 361,805 | (35,724 | ) | 326,081 | ||||||||
Other Income (Expense) | ||||||||||||
Loss from equity method investees | (6,397 | ) | 387 | (6,010 | ) | |||||||
Other income, net | 1,965 | — | 1,965 | |||||||||
Interest expense | (108,659 | ) | — | (108,659 | ) | |||||||
Total Other Expense, net | (113,091 | ) | 387 | (112,704 | ) | |||||||
Income Before Income Taxes | 248,714 | (35,337 | ) | 213,377 | ||||||||
Income Tax Expense | 86,633 | (54,039 | ) | 32,594 | ||||||||
Net Income | 162,081 | 18,702 | 180,783 | |||||||||
Preferred Stock Dividends | 11,496 | — | 11,496 | |||||||||
Net Income Available for Common Stockholders | $ | 150,585 | $ | 18,702 | $ | 169,287 | ||||||
Earnings per Share | ||||||||||||
Basic | $ | 1.90 | $ | 2.14 | ||||||||
Diluted | $ | 1.86 | $ | 1.94 | ||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||
Basic | 79,063 | 79,063 | ||||||||||
Diluted | 87,263 | 87,263 | ||||||||||
Net Income | $ | 162,081 | $ | 18,702 | $ | 180,783 | ||||||
Other Comprehensive Loss | ||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||
Unrealized change in fair value net of ineffective portion | (7,961 | ) | 7,961 | — | ||||||||
Effective portion reclassified to earnings during the period | (39,810 | ) | 39,810 | — | ||||||||
Total Other Comprehensive Loss | (47,771 | ) | 47,771 | — | ||||||||
Income Tax Benefit | (16,720 | ) | 16,720 | — | ||||||||
Net Other Comprehensive Loss | (31,051 | ) | 31,051 | — | ||||||||
Comprehensive Income | $ | 131,030 | $ | 49,753 | $ | 180,783 |
142
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 23 — Selected Quarterly Financial Data — Unaudited
Unaudited quarterly financial data are as follows (the information below has been restated where noted to give effect to the restatement discussed in Note 22, “Restatement of Previously Issued Consolidated Financial Statements” and restated quarterly consolidated financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013 and March 31, 2015 and 2014 included subsequently within this Form 10-K) (in thousands, except per share amounts):
Quarter Ended | ||||||||||||||||
June 30,(2) 2015 | March 31,(3) 2015 (Restated) | December 31,(4) 2014 (Restated) | September 30, 2014 (Restated) | |||||||||||||
Revenues | $ | 219,460 | $ | 221,580 | $ | 502,971 | $ | 461,441 | ||||||||
Operating income (loss) | (1,952,080 | ) | (698,583 | ) | (168,420 | ) | 108,192 | |||||||||
Net income (loss) | $ | (1,690,004 | ) | $ | (495,061 | ) | $ | (275,963 | ) | $ | 27,190 | |||||
Preferred stock dividends | 2,864 | 2,862 | 2,870 | 2,872 | ||||||||||||
Net income (loss) attributable to common stockholders | $ | (1,692,868 | ) | $ | (497,923 | ) | $ | (278,833 | ) | $ | 24,318 | |||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||
Basic | $ | (17.92 | ) | $ | (5.27 | ) | $ | (2.97 | ) | $ | 0.26 | |||||
Diluted | (17.92 | ) | (5.27 | ) | (2.97 | ) | 0.24 |
(1) | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. |
(2) | Included in Operating income (loss) for the three months ended June 30, 2015 is impairment of oil and natural gas properties of $1,852.3 million. |
(3) | Included in Operating income (loss) for the three months ended March 31, 2015 is impairment of oil and natural gas properties of $569.6 million. |
(4) | Included in Operating income (loss) for the three months ended December 31, 2014 is goodwill impairment of $329.3 million. |
Quarter Ended | ||||||||||||||||
June 30, 2014 (Restated) | March 31, 2014 (Restated) | December 31, 2013 (Restated) | September 30, 2013 (Restated) | |||||||||||||
Revenues | $ | 301,308 | $ | 284,854 | $ | 273,814 | $ | 293,147 | ||||||||
Operating income | 32,786 | 66,458 | 46,579 | 71,983 | ||||||||||||
Net income (loss) | $ | (15,403 | ) | $ | 6,318 | $ | 1,928 | $ | 25,282 | |||||||
Preferred stock dividends | 2,872 | 2,872 | 2,872 | 2,873 | ||||||||||||
Net income (loss) attributable to common stockholders | $ | (18,275 | ) | $ | 3,446 | $ | (944 | ) | $ | 22,409 | ||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||
Basic | $ | (0.24 | ) | $ | 0.05 | $ | (0.01 | ) | $ | 0.30 | ||||||
Diluted | (0.24 | ) | 0.05 | (0.01 | ) | 0.27 |
(1) | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. |
143
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 23 — Selected Quarterly Financial Data — Unaudited – (continued)
Quarter Ended | ||||||||||||
March 31, 2015 (As Reported) | December 31, 2014 (As Reported) | September 30, 2014 (As Reported) | ||||||||||
Revenues | $ | 260,192 | $ | 357,755 | $ | 403,231 | ||||||
Operating income (loss) | (834,455 | ) | (314,928 | ) | 51,139 | |||||||
Net loss | $ | (584,317 | ) | $ | (373,879 | ) | $ | (6,403 | ) | |||
Preferred stock dividends | 2,862 | 2,870 | 2,872 | |||||||||
Net loss attributable to common stockholders | $ | (587,179 | ) | $ | (376,749 | ) | $ | (9,275 | ) | |||
Net loss per share attributable to common stockholders(1) | ||||||||||||
Basic | $ | (6.22 | ) | $ | (4.01 | ) | $ | (0.10 | ) | |||
Diluted | (6.22 | ) | (4.01 | ) | (0.10 | ) |
(1) | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. |
Quarter Ended | ||||||||||||||||
June 30, 2014 (As Reported) | March 31, 2014 (As Reported) | December 31, 2013 (As Reported) | September 30, 2013 (As Reported) | |||||||||||||
Revenues | $ | 324,134 | $ | 285,183 | $ | 296,816 | $ | 324,592 | ||||||||
Operating income | 54,677 | 64,801 | 61,502 | 99,431 | ||||||||||||
Net income (loss) | $ | (1,815 | ) | $ | 7,292 | $ | 10,495 | $ | 43,139 | |||||||
Preferred stock dividends | 2,872 | 2,872 | 2,872 | 2,873 | ||||||||||||
Net income (loss) attributable to common stockholders | $ | (4,687 | ) | $ | 4,420 | $ | 7,623 | $ | 40,266 | |||||||
Net income (loss) per share attributable to common stockholders(1) | ||||||||||||||||
Basic | $ | (0.06 | ) | $ | 0.06 | $ | 0.10 | $ | 0.53 | |||||||
Diluted | (0.06 | ) | 0.06 | 0.10 | 0.51 |
(1) | The sum of the individual quarterly earnings per share may not agree with year-to-date earnings per share because each quarterly calculation is based on the income for that quarter and the weighted average number of shares outstanding during that quarter. |
Note 24 — Supplementary Oil and Gas Information — Unaudited
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 (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Property acquisitions | ||||||||||||
Proved | $ | — | $ | 2,046,879 | $ | 108,825 | ||||||
Unevaluated | 2,304 | 924,882 | 52,339 | |||||||||
Exploration costs | 38,183 | 153,136 | 168,512 | |||||||||
Development costs | 608,605 | 632,262 | 633,868 |
144
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 24 — Supplementary Oil and Gas Information — Unaudited – (continued)
Oil and natural gas property costs excluded from the amortization base represent investments in unevaluated properties and include non-producing leasehold, geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these costs until the property has been evaluated. We also allocate a portion of our acquisition costs to unevaluated properties based on fair value. Costs are transferred to proved properties as the properties are evaluated or over the life of the reservoir. Wells in progress are transferred into the amortization base once the results of drilling activities are known. We had no exploratory wells in progress at June 30, 2015. At June 30, 2015, we excluded from the amortization base the following costs related to unevaluated property costs(in thousands):
Net Costs Incurred During the Years Ended June 30, | Balance as of June 30, 2015 | |||||||||||||||||||
2012 and prior | 2013 | 2014 | 2015 | |||||||||||||||||
Unevaluated Properties (acquisition costs) | $ | 928 | $ | — | $ | 435,429 | $ | — | $ | 436,357 |
Estimated Net Quantities of Oil and Natural Gas Reserves
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 reservoir engineers and audited by NSAI. Reserve volumes and values were determined under the method prescribed by the SEC, which requires the application of the 12-month average price for natural gas and oil calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period to the end of the reporting period and current costs held constant throughout the projected reserve life. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise that those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.
Estimated quantities of proved domestic oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves in thousands of barrels (“MBbls”) and millions of cubic feet (“MMcf”) for each of the periods indicated were as follows:
Oil (MBbls) | Natural Gas (MMcf) | Total (MBOE) | ||||||||||
Proved reserves at June 30, 2012 | 84,793 | 208,990 | 119,624 | |||||||||
Production | (10,318 | ) | (32,354 | ) | (15,710 | ) | ||||||
Extensions and discoveries | 40,690 | 40,714 | 47,476 | |||||||||
Revisions of previous estimates | 14,380 | 7,903 | 15,697 | |||||||||
Reclassification of proved undeveloped | (1,123 | ) | (1,755 | ) | (1,416 | ) | ||||||
Purchases of reserves | 5,225 | 45,623 | 12,829 | |||||||||
Proved reserves at June 30, 2013 | 133,647 | 269,121 | 178,500 | |||||||||
Production | (10,978 | ) | (32,754 | ) | (16,437 | ) | ||||||
Extensions and discoveries | 17,141 | 19,703 | 20,424 | |||||||||
Revisions of previous estimates | (3,567 | ) | (29,822 | ) | (8,537 | ) | ||||||
Sales of reserves | (4,159 | ) | (3,378 | ) | (4,722 | ) | ||||||
Purchases of reserves | 53,305 | 141,986 | 76,970 | |||||||||
Proved reserves at June 30, 2014 | 185,389 | 364,856 | 246,198 | |||||||||
Production | (15,259 | ) | (37,472 | ) | (21,504 | ) | ||||||
Extensions and discoveries | 10,573 | 40,330 | 17,295 | |||||||||
Revisions of previous estimates | (33,730 | ) | (75,617 | ) | (46,333 | ) | ||||||
Sales of reserves | (9,901 | ) | (13,554 | ) | (12,160 | ) | ||||||
Proved reserves at June 30, 2015 | 137,072 | 278,543 | 183,496 |
145
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 24 — Supplementary Oil and Gas Information — Unaudited – (continued)
Oil (MBbls) | Natural Gas (MMcf) | Total (MBOE) | ||||||||||
Proved developed reserves | ||||||||||||
June 30, 2012 | 63,308 | 110,310 | 81,693 | |||||||||
June 30, 2013 | 80,223 | 175,623 | 109,493 | |||||||||
June 30, 2014 | 112,789 | 222,916 | 149,942 | |||||||||
June 30, 2015 | 94,013 | 187,993 | 125,345 | |||||||||
Proved undeveloped reserves | ||||||||||||
June 30, 2012 | 21,485 | 98,680 | 37,931 | |||||||||
June 30, 2013 | 53,424 | 93,498 | 69,007 | |||||||||
June 30, 2014 | 72,600 | 141,940 | 96,256 | |||||||||
June 30, 2015 | 43,059 | 90,550 | 58,151 |
Our proved developed reserve estimates decreased by 24.6 MMBOE or 16% to 125.3 MMBOE at June 30, 2015 from 149.9 MMBOE at June 30, 2014. The decrease was primarily due to:
• | Downward revision of 12.8 MMBOE, primarily due to the effect of reduced oil and gas prices, |
• | Divestiture of 11.7 MMBOE, and |
• | Production of 21.5 MMBOE. |
Offset by:
• | Additions of 8.5 MMBOE primarily from drilling, recompletions, and wells returned to production that were not previously booked, more than 80% of which are from six fields: South Pass 78, Lomond North, West Delta 73, Main Pass 61, South Timbalier 54 and South Pass 49, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Our proved undeveloped reserve estimates decreased by 38.1 MMBOE or 40% to 58.2 MMBOE at June 30, 2015 from 96.3 MMBOE at June 30, 2014. The increase was primarily due to:
• | Downward revisions of 33.6 MMBOE comprised of (i) 7.3 MMBOE due to the effect of reduced oil and gas prices, (ii) 7.0 MMBOE due to certain wells that were no longer scheduled for development within five years, and (iii) 19.3 MMBOE due to new data and field studies. Of the 19.3 MMBOE of downward revisions due to new data and field studies, more than 80% occurred in the following seven fields: Grand Isle 16, Ship Shoal 208, South Timbalier 21, South Timbalier 26, Vermilion 164, West Delta 30, and West Delta 73, and |
• | Conversion of 12.9 MMBOE from proved undeveloped to proved developed reserves. |
Offset by:
• | Additions of 8.8 MMBOE, primarily from additional drilling locations to make up for the lower throughput per well in West Delta 73, a replacement location at Bayou Carlin, and from the identification of new proved undeveloped reserves locations in West Delta 30 and Main Pass 73. |
In the fiscal year ended June 30, 2015, we developed approximately 13.4% of our PUD reserves included in our June 30, 2014 reserve report, consisting of 21 gross, 21 net wells at a net cost of approximately $237 million.
We update and approve our reserves development plan on an annual basis, which includes our program to drill PUD locations. Updates to our reserves development plan are based upon long range criteria, including
146
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 24 — Supplementary Oil and Gas Information — Unaudited – (continued)
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 proved undeveloped locations will be developed within five years from the time they are first recognized as proved undeveloped locations in our reserve report, with the exception of four locations totaling 3,560 MBOE or 6.1%. of our PUD reserves. These four locations are to be sidetracked from existing wellbores which are still producing economically thus cannot be drilled until the proved developed producing zones deplete.
Standardized Measure of Discounted Future Net Cash Flows
Future cash inflows as of June 30, 2015 were computed using the following prices. The average oil price prior to quality, transportation fees, and regional price differentials was $68.17 per barrel of oil (calculated using the unweighted average first-day-of-the-month West Texas Intermediate posted prices during the 12-month period ending on June 30, 2015). The report forecasts crude oil and NGL production separately. The average realized adjusted product prices weighted by production over the remaining lives of the properties, used to determine future net revenues were $73.79 per barrel of oil and $29.54 per barrel of NGLs, after adjusting for quality, transportation fees, and regional price differentials. The $73.79 per barrel realized oil price compares to an unweighted average first-day-of-the-month West Texas Intermediate price of $68.17 per barrel (differential of $5.62 per barrel).
For natural gas, the average Henry Hub price used was $3.39 per MMBtu, prior to adjustments for energy content, transportation fees, and regional price differentials (calculated using the unweighted average first-day-of-the-month Henry Hub spot price). The average adjusted realized natural gas price, weighted by production over the remaining lives of the properties used to determine future net revenues, was $3.08 per Mcf after adjusting for energy content, transportation fees, and regional price differentials.
The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2015, 2014 and 2013 are as follows (in thousands):
June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Future cash inflows | $ | 10,641,151 | $ | 20,162,506 | $ | 15,048,978 | ||||||
Less related future | ||||||||||||
Production costs | 4,131,526 | 5,500,669 | 3,657,595 | |||||||||
Development and abandonment costs | 1,970,526 | 2,959,994 | 1,838,159 | |||||||||
Income taxes | 168,655 | 2,546,155 | 2,591,351 | |||||||||
Future net cash flows | 4,370,444 | 9,155,688 | 6,961,873 | |||||||||
Ten percent annual discount for estimated timing of cash flows | 1,613,034 | 3,208,163 | 2,480,351 | |||||||||
Standardized measure of discounted future net cash flows | $ | 2,757,410 | $ | 5,947,525 | $ | 4,481,522 |
147
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 24 — Supplementary Oil and Gas Information — Unaudited – (continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves follows (in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Beginning of year | $ | 5,947,525 | $ | 4,481,522 | $ | 3,305,489 | ||||||
Revisions of previous estimates | ||||||||||||
Changes in prices and costs | (2,959,883 | ) | (196,159 | ) | (106,002 | ) | ||||||
Changes in quantities | (2,390,099 | ) | (389,570 | ) | 635,562 | |||||||
Additions to proved reserves resulting from extensions, discoveries and improved recovery, less related costs | 201,234 | 533,133 | 1,598,548 | |||||||||
Purchases (sales) of reserves in place | (244,507 | ) | 1,735,957 | 480,111 | ||||||||
Accretion of discount | 760,175 | 614,964 | 429,745 | |||||||||
Sales, net of production and gathering and transportation costs | (676,949 | ) | (836,019 | ) | (842,268 | ) | ||||||
Net change in income taxes | 1,576,954 | 14,134 | (676,158 | ) | ||||||||
Changes in rate of production | (191,668 | ) | (253,290 | ) | (456,254 | ) | ||||||
Development costs incurred | 237,173 | 247,865 | 125,925 | |||||||||
Changes in estimated future development and abandonment costs and other | 497,455 | (5,012 | ) | (13,176 | ) | |||||||
Net change | (3,190,115 | ) | 1,466,003 | 1,176,033 | ||||||||
End of year | $ | 2,757,410 | $ | 5,947,525 | $ | 4,481,522 |
Note 25 — Supplemental Guarantor Information
Our indirect, 100% wholly owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011, each of which were replaced with identical notes issued in registered offerings. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s revolving credit facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC generally requires the issuer and guarantors to file separate financial statements. We meet the conditions in Rule 3-10 to instead report information about the assets, liabilities, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to our financial statements, condensed consolidating financial information for the same periods as those presented in our financial statements.
The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses.
148
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
June 30, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 37,053 | $ | 719,609 | $ | — | $ | 186 | $ | — | $ | 756,848 | ||||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 68,514 | 36,963 | (5,234 | ) | 100,243 | |||||||||||||||||
Joint interest billings | — | 2,015 | — | 10,418 | — | 12,433 | ||||||||||||||||||
Other | 622 | 17,819 | 140 | 24,932 | — | 43,513 | ||||||||||||||||||
Prepaid expenses and other current assets | 280 | 13,211 | — | 11,469 | (662 | ) | 24,298 | |||||||||||||||||
Restricted cash | — | — | 9,359 | — | 9,359 | |||||||||||||||||||
Derivative financial instruments | — | 21,341 | — | 888 | — | 22,229 | ||||||||||||||||||
Total Current Assets | 37,955 | 773,995 | 68,654 | 94,215 | (5,896 | ) | 968,923 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 2,112,635 | 1,408,585 | 49,539 | 3,570,759 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 21,820 | — | 21,820 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 2,112,635 | 1,430,405 | 49,539 | 3,592,579 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Derivative financial instruments | — | 3,898 | — | — | — | 3,898 | ||||||||||||||||||
Equity investments | — | 428,368 | — | 3,591,757 | (4,009,290 | ) | 10,835 | |||||||||||||||||
Intercompany receivables | 122,039 | 1,626,679 | — | 93,844 | (1,842,562 | ) | — | |||||||||||||||||
Restricted cash | — | 31,000 | — | 1,667 | — | 32,667 | ||||||||||||||||||
Other assets and debt issuance costs, net | 176,861 | 464,617 | — | 8,729 | (568,280 | ) | 81,927 | |||||||||||||||||
Total Other Assets | 298,900 | 2,554,562 | — | 3,695,997 | (6,420,132 | ) | 129,327 | |||||||||||||||||
Total Assets | $ | 336,855 | $ | 3,328,557 | $ | 2,181,289 | $ | 5,220,617 | $ | (6,376,489 | ) | $ | 4,690,829 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 39,378 | $ | 41,027 | $ | 81,052 | $ | (5,118 | ) | $ | 156,339 | |||||||||||
Accrued liabilities | 976 | 69,566 | 16,060 | 166,851 | (98,147 | ) | 155,306 | |||||||||||||||||
Deferred income taxes | 24,174 | — | — | — | (24,174 | ) | — | |||||||||||||||||
Asset retirement obligations | — | — | 624 | 32,662 | — | 33,286 | ||||||||||||||||||
Derivative financial instruments | — | 1,603 | — | 1,058 | — | 2,661 | ||||||||||||||||||
Current maturities of long-term debt | — | 7,283 | — | 4,112 | — | 11,395 | ||||||||||||||||||
Total Current Liabilities | 25,150 | 117,830 | 57,711 | 285,735 | (127,439 | ) | 358,987 | |||||||||||||||||
Long-term debt, less current maturities | 354,218 | 3,548,896 | — | 938,923 | (245,000 | ) | 4,597,037 | |||||||||||||||||
Intercompany notes payable | — | — | — | 565,105 | (565,105 | ) | — | |||||||||||||||||
Deferred income taxes | — | — | — | — | — | — | ||||||||||||||||||
Asset retirement obligations | — | 50 | 251,444 | 209,431 | (7,126 | ) | 453,799 | |||||||||||||||||
Derivative financial instruments | — | 1,358 | — | — | — | 1,358 | ||||||||||||||||||
Accumulated losses in excess of equity investments | 686,209 | — | — | — | (686,209 | ) | — | |||||||||||||||||
Intercompany payables | — | — | 1,721,211 | — | (1,721,211 | ) | — | |||||||||||||||||
Other liabilities | — | 5,332 | — | 3,038 | — | 8,370 | ||||||||||||||||||
Total Liabilities | 1,065,577 | 3,673,466 | 2,030,366 | 2,002,232 | (3,352,090 | ) | 5,419,551 | |||||||||||||||||
Stockholders’ Equity (Deficit) | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 472 | 1 | — | 12 | (13 | ) | 472 | |||||||||||||||||
Additional paid-in capital | 1,843,918 | 2,252,142 | 78,599 | 7,377,784 | (9,708,525 | ) | 1,843,918 | |||||||||||||||||
Accumulated earnings (deficit) | (2,573,113 | ) | (2,597,052 | ) | 72,324 | (4,159,411 | ) | 6,684,139 | (2,573,113 | ) | ||||||||||||||
Total Stockholders’ Equity (Deficit) | (728,722 | ) | (344,909 | ) | 150,923 | 3,218,385 | (3,024,399 | ) | (728,722 | ) | ||||||||||||||
Total Liabilities and Stockholders’ Equity (Deficit) | $ | 336,855 | $ | 3,328,557 | $ | 2,181,289 | $ | 5,220,617 | $ | (6,376,489 | ) | $ | 4,690,829 |
149
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
June 30, 2014 (Restated) | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 135,703 | $ | 3,723 | $ | — | $ | 6,380 | $ | — | $ | 145,806 | ||||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 127,773 | 50,990 | (11,688 | ) | 167,075 | |||||||||||||||||
Joint interest billings | — | 1,833 | — | 11,065 | — | 12,898 | ||||||||||||||||||
Other | 10 | 3,452 | 517 | 1,460 | (1 | ) | 5,438 | |||||||||||||||||
Prepaid expenses and other current assets | 230 | 27,705 | 350 | 44,245 | — | 72,530 | ||||||||||||||||||
Deferred income taxes | — | 27,424 | — | 25,163 | — | 52,587 | ||||||||||||||||||
Derivative financial instruments | — | 1,425 | — | — | — | 1,425 | ||||||||||||||||||
Total Current Assets | 135,943 | 65,562 | 128,640 | 139,303 | (11,689 | ) | 457,759 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,227,584 | 3,197,765 | 1,914 | 6,427,263 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,227,584 | 3,217,525 | 1,914 | 6,447,023 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Goodwill | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Derivative financial instruments | — | 3,035 | — | — | — | 3,035 | ||||||||||||||||||
Equity investments | 1,681,640 | 2,871,756 | — | 2,291,045 | (6,803,798 | ) | 40,643 | |||||||||||||||||
Intercompany receivables | 102,489 | 1,627,931 | — | 80,983 | (1,811,403 | ) | — | |||||||||||||||||
Restricted cash | — | — | 325 | 6,025 | — | 6,350 | ||||||||||||||||||
Other assets and debt issuance costs, net | 178,299 | 42,155 | — | 7,940 | (171,000 | ) | 57,394 | |||||||||||||||||
Total Other Assets | 1,962,428 | 4,544,877 | 325 | 2,715,286 | (8,786,201 | ) | 436,715 | |||||||||||||||||
Total Assets | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 64,533 | $ | 150,909 | $ | 214,215 | $ | (11,881 | ) | $ | 417,776 | |||||||||||
Accrued liabilities | 1,640 | 12,501 | 28,750 | 154,587 | (63,952 | ) | 133,526 | |||||||||||||||||
Notes payable | — | 21,967 | — | — | — | 21,967 | ||||||||||||||||||
Deferred income taxes | 19,185 | — | — | — | (19,185 | ) | — | |||||||||||||||||
Asset retirement obligations | — | — | 39,819 | 39,830 | — | 79,649 | ||||||||||||||||||
Derivative financial instruments | — | 5,517 | — | 26,440 | — | 31,957 | ||||||||||||||||||
Current maturities of long-term debt | — | 14,093 | — | 927 | — | 15,020 | ||||||||||||||||||
Total Current Liabilities | 20,825 | 118,611 | 219,478 | 435,999 | (95,018 | ) | 699,895 | |||||||||||||||||
Long-term debt, less current maturities | 342,986 | 2,305,906 | — | 1,266,732 | (171,000 | ) | 3,744,624 | |||||||||||||||||
Deferred income taxes | — | 177,007 | — | 470,755 | 19,207 | 666,969 | ||||||||||||||||||
Asset retirement obligations | — | 49 | 247,272 | 232,864 | — | 480,185 | ||||||||||||||||||
Derivative financial instruments | — | 2,166 | — | 2,140 | — | 4,306 | ||||||||||||||||||
Intercompany payables | — | — | 1,640,094 | — | (1,640,094 | ) | — | |||||||||||||||||
Other liabilities | — | — | — | 10,958 | — | 10,958 | ||||||||||||||||||
Total Liabilities | 363,811 | 2,603,739 | 2,106,844 | 2,419,448 | (1,886,905 | ) | 5,606,937 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 468 | 1 | 10 | (11 | ) | 468 | ||||||||||||||||||
Additional paid-in capital | 1,837,462 | 2,092,439 | 273,129 | 3,580,005 | (5,945,573 | ) | 1,837,462 | |||||||||||||||||
Accumulated earnings (deficit) | (103,371 | ) | (85,740 | ) | 976,576 | 72,651 | (963,487 | ) | (103,371 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,734,560 | 2,006,700 | 1,249,705 | 3,652,666 | (6,909,071 | ) | 1,734,560 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 |
150
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended June 30, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non- Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 591,349 | $ | 469,102 | $ | (7,720 | ) | $ | 1,052,731 | |||||||||||
Natural gas sales | — | — | 67,169 | 50,113 | — | 117,282 | ||||||||||||||||||
Gain on derivative financial instruments | — | 195,357 | — | 40,082 | 235,439 | |||||||||||||||||||
Total Revenues | — | 195,357 | 658,518 | 559,297 | (7,720 | ) | 1,405,452 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | 296 | 246,904 | 208,615 | 7,720 | 463,535 | ||||||||||||||||||
Production taxes | — | 33 | 3,333 | 5,019 | — | 8,385 | ||||||||||||||||||
Gathering and transportation | — | — | 21,144 | — | — | 21,144 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 362,421 | 333,654 | 9,446 | 705,521 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 26,448 | 23,633 | — | 50,081 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | 842,621 | 1,699,590 | (120,327 | ) | 2,421,884 | |||||||||||||||||
Goodwill impairment | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
General and administrative expense | 8,409 | 11,801 | 56,985 | 39,305 | — | 116,500 | ||||||||||||||||||
Total Costs and Expenses | 8,409 | 12,130 | 1,559,856 | 2,639,109 | (103,161 | ) | 4,116,343 | |||||||||||||||||
Operating Income (Loss) | (8,409 | ) | 183,227 | (901,338 | ) | (2,079,812 | ) | 95,441 | (2,710,891 | ) | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | (2,415,367 | ) | (2,601,331 | ) | — | (2,527,727 | ) | 7,527,260 | (17,165 | ) | ||||||||||||||
Other income (expense) – net | 20,530 | 14,898 | — | 17,849 | (49,101 | ) | 4,176 | |||||||||||||||||
Interest expense | (24,669 | ) | (256,918 | ) | (2,914 | ) | (87,908 | ) | 49,101 | (323,308 | ) | |||||||||||||
Total Other Income (Expense) | (2,419,506 | ) | (2,843,351 | ) | (2,914 | ) | (2,597,786 | ) | 7,527,260 | (336,297 | ) | |||||||||||||
Income (Loss) Before Income Taxes | (2,427,915 | ) | (2,660,124 | ) | (904,252 | ) | (4,677,598 | ) | 7,622,701 | (3,047,188 | ) | |||||||||||||
Income Tax Expense (Benefit) | 5,923 | (149,562 | ) | — | (445,536 | ) | (24,175 | ) | (613,350 | ) | ||||||||||||||
Net Income (Loss) | (2,433,838 | ) | (2,510,562 | ) | (904,252 | ) | (4,232,062 | ) | 7,646,876 | (2,433,838 | ) | |||||||||||||
Preferred Stock Dividends | 11,468 | — | — | — | — | 11,468 | ||||||||||||||||||
Net Income (Loss) Attributable to Common Stockholders | $ | (2,445,306 | ) | $ | (2,510,562 | ) | $ | (904,252 | ) | $ | (4,232,062 | ) | $ | 7,646,876 | $ | (2,445,306 | ) |
151
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended June 30, 2014 (Restated) | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non- Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 1,046,263 | $ | 57,945 | $ | — | $ | 1,104,208 | ||||||||||||
Natural gas sales | — | — | 132,225 | 3,658 | — | 135,883 | ||||||||||||||||||
Loss on derivative financial instruments | — | (75,889 | ) | — | (11,079 | ) | — | (86,968 | ) | |||||||||||||||
Total Revenues | — | (75,889 | ) | 1,178,488 | 50,524 | — | 1,153,123 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (325 | ) | 348,027 | 18,045 | — | 365,747 | |||||||||||||||||
Production taxes | — | 51 | 4,716 | 660 | — | 5,427 | ||||||||||||||||||
Gathering and transportation | — | — | 23,532 | — | — | 23,532 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 389,793 | 26,340 | (2,107 | ) | 414,026 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 28,161 | 2,022 | — | 30,183 | ||||||||||||||||||
General and administrative expense | 7,380 | 1,134 | 81,380 | 6,508 | — | 96,402 | ||||||||||||||||||
Total Costs and Expenses | 7,380 | 860 | 875,609 | 53,575 | (2,107 | ) | 935,317 | |||||||||||||||||
Operating Income (Loss) | (7,380 | ) | (76,749 | ) | 302,879 | (3,051 | ) | 2,107 | 217,806 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 26,009 | 299,556 | — | 91,741 | (422,537 | ) | (5,231 | ) | ||||||||||||||||
Other income (expense) – net | 19,923 | 1,954 | — | 17,808 | (36,387 | ) | 3,298 | |||||||||||||||||
Interest expense | (14,485 | ) | (138,336 | ) | (5,957 | ) | (40,337 | ) | 36,387 | (162,728 | ) | |||||||||||||
Total Other Income (Expense) | 31,447 | 163,174 | (5,957 | ) | 69,212 | (422,537 | ) | (164,661 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 24,067 | 86,425 | 296,922 | 66,161 | (420,430 | ) | 53,145 | |||||||||||||||||
Income Tax Expense (Benefit) | 5,942 | 29,989 | — | (911 | ) | 35,020 | ||||||||||||||||||
Net Income (Loss) | 18,125 | 56,436 | 296,922 | 67,072 | (420,430 | ) | 18,125 | |||||||||||||||||
Preferred Stock Dividends | 11,489 | — | — | — | — | 11,489 | ||||||||||||||||||
Net Income (Loss) Attributable to Common Stockholders | $ | 6,636 | $ | 56,436 | $ | 296,922 | $ | 67,072 | $ | (420,430 | ) | $ | 6,636 |
152
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Year Ended June 30, 2013 (Restated) | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non- Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 1,067,687 | $ | — | $ | — | $ | 1,067,687 | ||||||||||||
Natural gas sales | — | — | 112,753 | — | — | 112,753 | ||||||||||||||||||
Loss on derivative financial instruments | — | (21,508 | ) | — | — | — | (21,508 | ) | ||||||||||||||||
Total Revenues | — | (21,508 | ) | 1,180,440 | — | — | 1,158,932 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (3,249 | ) | 340,412 | — | — | 337,163 | |||||||||||||||||
Production taxes | — | (658 | ) | 5,904 | — | — | 5,246 | |||||||||||||||||
Gathering and transportation | — | — | 24,168 | — | — | 24,168 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 359,819 | 3,972 | — | 363,791 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 30,885 | — | — | 30,885 | ||||||||||||||||||
General and administrative expense | 7,439 | 2,820 | 61,089 | 250 | — | 71,598 | ||||||||||||||||||
Total Costs and Expenses | 7,439 | (1,087 | ) | 822,277 | 4,222 | — | 832,851 | |||||||||||||||||
Operating Income (Loss) | (7,439 | ) | (20,421 | ) | 358,163 | (4,222 | ) | — | 326,081 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 175,218 | 345,178 | — | 177,366 | (703,772 | ) | (6,010 | ) | ||||||||||||||||
Other income (expense) – net | 18,584 | 1,849 | 12 | 17,833 | (36,313 | ) | 1,965 | |||||||||||||||||
Interest expense | (5 | ) | (93,200 | ) | (15,160 | ) | (36,607 | ) | 36,313 | (108,659 | ) | |||||||||||||
Total Other Income (Expense) | 193,797 | 253,827 | (15,148 | ) | 158,592 | (703,772 | ) | (112,704 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 186,358 | 233,406 | 343,015 | 154,370 | (703,772 | ) | 213,377 | |||||||||||||||||
Income Tax Expense (Benefit) | 5,575 | 31,715 | — | (4,696 | ) | — | 32,594 | |||||||||||||||||
Net Income (Loss) | 180,783 | 201,691 | 343,015 | 159,066 | (703,772 | ) | 180,783 | |||||||||||||||||
Preferred Stock Dividends | 11,496 | — | — | — | — | 11,496 | ||||||||||||||||||
Net Income (Loss) Attributable to Common Stockholders | $ | 169,287 | $ | 201,691 | $ | 343,015 | $ | 159,066 | $ | (703,772 | ) | $ | 169,287 |
153
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended June 30, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (2,433,838 | ) | $ | (2,510,562 | ) | $ | (904,252 | ) | $ | (4,232,062 | ) | $ | 7,646,876 | $ | (2,433,838 | ) | |||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 362,421 | 333,654 | 9,446 | 705,521 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | 842,621 | 1,699,590 | (120,327 | ) | 2,421,884 | |||||||||||||||||
Goodwill impairment | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Deferred income tax expense | 4,989 | (149,563 | ) | — | (445,635 | ) | (24,174 | ) | (614,383 | ) | ||||||||||||||
Change in fair value of derivative financial instruments | — | (40,929 | ) | — | (11,107 | ) | — | (52,036 | ) | |||||||||||||||
Accretion of asset retirement obligations | — | — | 26,448 | 23,633 | — | 50,081 | ||||||||||||||||||
Loss from equity method investees | 2,415,367 | 2,601,331 | — | 2,527,727 | (7,527,260 | ) | 17,165 | |||||||||||||||||
Amortization and write-off of debt issuance costs and other | 12,670 | 21,530 | — | (10,953 | ) | — | 23,247 | |||||||||||||||||
Stock-based compensation | 4,124 | — | — | — | — | 4,124 | ||||||||||||||||||
Changes in operating assets and liabilities | — | |||||||||||||||||||||||
Accounts receivable | (614 | ) | 4,036 | 59,637 | (11,891 | ) | 116 | 51,284 | ||||||||||||||||
Prepaid expenses and other current assets | (49 | ) | 14,494 | 1,012 | 32,605 | — | 48,062 | |||||||||||||||||
Settlement of asset retirement obligations | — | — | (47,923 | ) | (58,650 | ) | — | (106,573 | ) | |||||||||||||||
Accounts payable and accrued liabilities | (17,729 | ) | (272,935 | ) | (24,768 | ) | 34,213 | 168,141 | (113,078 | ) | ||||||||||||||
Net Cash Provided by (Used in) Operating Activities | (15,080 | ) | (332,598 | ) | 315,196 | 210,417 | 152,818 | 330,753 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (301 | ) | — | — | (301 | ) | ||||||||||||||||
Capital expenditures | — | — | (325,836 | ) | (397,993 | ) | — | (723,829 | ) | |||||||||||||||
Insurance payments received | — | — | 3,230 | 690 | — | 3,920 | ||||||||||||||||||
Change in equity method investments | — | — | — | 12,642 | — | 12,642 | ||||||||||||||||||
Intercompany investment | (50,000 | ) | 289,999 | — | (86,999 | ) | (153,000 | ) | — | |||||||||||||||
Transfers to restricted cash | — | (10,000 | ) | 325 | (5,001 | ) | — | (14,676 | ) | |||||||||||||||
Proceeds from the sale of properties | — | — | 7,386 | 9,545 | 245,000 | 261,931 | ||||||||||||||||||
Other | — | — | — | (135 | ) | — | (135 | ) | ||||||||||||||||
Net Cash (Used in) Investing Activities | (50,000 | ) | 279,999 | (315,196 | ) | (467,251 | ) | 92,000 | (460,448 | ) | ||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,336 | — | — | — | — | 2,336 | ||||||||||||||||||
Dividends to shareholders – common | (24,436 | ) | — | — | — | — | (24,436 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (11,468 | ) | — | — | — | — | (11,468 | ) | ||||||||||||||||
Cash restricted under revolving credit facility related to property sold | — | (21,000 | ) | — | — | — | (21,000 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 2,261,572 | — | 570,000 | (245,000 | ) | 2,586,572 | |||||||||||||||||
Payments on long-term debt | — | (1,429,885 | ) | — | (317,964 | ) | — | (1,747,849 | ) | |||||||||||||||
Debt issuance costs | — | (42,202 | ) | — | (1,150 | ) | — | (43,352 | ) | |||||||||||||||
Other | (2 | ) | (246 | ) | 182 | (66 | ) | |||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (33,570 | ) | 768,485 | — | 250,640 | (244,818 | ) | 740,737 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | (98,650 | ) | 715,886 | — | (6,194 | ) | — | 611,042 | ||||||||||||||||
Cash and Cash Equivalents, beginning of period | 135,703 | 3,723 | — | 6,380 | — | 145,806 | ||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 37,053 | $ | 719,609 | $ | — | $ | 186 | $ | — | $ | 756,848 |
154
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended June 30, 2014 (Restated) | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 18,125 | $ | 56,436 | $ | 296,922 | $ | 67,072 | $ | (420,430 | ) | $ | 18,125 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 389,793 | 26,340 | (2,107 | ) | 414,026 | |||||||||||||||||
Deferred income tax expense | 2,301 | 29,989 | — | (911 | ) | — | 31,379 | |||||||||||||||||
Change in derivative financial instruments | — | 60,037 | — | 9,619 | — | 69,656 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 28,161 | 2,022 | — | 30,183 | ||||||||||||||||||
Loss from equity method investees | (26,009 | ) | (299,556 | ) | — | (91,741 | ) | 422,537 | 5,231 | |||||||||||||||
Amortization and write-off of debt issuance costs and other | 7,219 | 6,555 | — | — | — | 13,774 | ||||||||||||||||||
Stock-based compensation | 6,712 | — | — | — | (1 | ) | 6,711 | |||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | (10 | ) | 22,708 | 22,212 | 18,372 | 1 | 63,283 | |||||||||||||||||
Prepaid expenses and other current assets | (18 | ) | 19,746 | 23 | (13,733 | ) | 1 | 6,019 | ||||||||||||||||
Settlement of asset retirement obligations | — | — | (57,391 | ) | — | — | (57,391 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | (5,852 | ) | 88,285 | (256,890 | ) | 1,284,956 | (1,166,035 | ) | (55,536 | ) | ||||||||||||||
Net Cash Provided by (Used in) Operating Activities | 2,468 | (15,800 | ) | 422,830 | 1,301,996 | (1,166,034 | ) | 545,460 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (37,657 | ) | (811,984 | ) | — | (849,641 | ) | |||||||||||||||
Capital expenditures | — | 16,746 | (513,096 | ) | (292,326 | ) | — | (788,676 | ) | |||||||||||||||
Insurance payments received | — | — | 1,983 | — | — | 1,983 | ||||||||||||||||||
Change in equity method investments | — | — | — | (34,294 | ) | — | (34,294 | ) | ||||||||||||||||
Intercompany investment | (185,568 | ) | (979,420 | ) | — | (2,570 | ) | 1,167,558 | — | |||||||||||||||
Transfers to restricted cash | — | — | (325 | ) | — | — | (325 | ) | ||||||||||||||||
Proceeds from the sale of properties | — | — | 126,265 | — | — | 126,265 | ||||||||||||||||||
Other | — | — | — | 113 | — | 113 | ||||||||||||||||||
Net Cash Used in (Provided by) Investing Activities | (185,568 | ) | (962,674 | ) | (422,830 | ) | (1,141,061 | ) | 1,167,558 | (1,544,575 | ) | |||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 3,994 | — | — | — | — | 3,994 | ||||||||||||||||||
Proceeds from convertible debt allocated to additional paid-in capital | 63,432 | — | — | — | — | 63,432 | ||||||||||||||||||
Repurchase of company common stock | (30,824 | ) | — | — | (153,439 | ) | — | (184,263 | ) | |||||||||||||||
Dividends to shareholders – common | (34,680 | ) | — | — | — | — | (34,680 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (11,489 | ) | — | — | — | — | (11,489 | ) | ||||||||||||||||
Proceeds from long-term debt | 336,568 | 3,085,145 | — | (840 | ) | — | 3,420,873 | |||||||||||||||||
Payments on long-term debt | — | (2,079,072 | ) | — | (413 | ) | — | (2,079,485 | ) | |||||||||||||||
Debt issuance costs | (9,585 | ) | (23,876 | ) | — | — | — | (33,461 | ) | |||||||||||||||
Other | 53 | — | — | — | (53 | ) | — | |||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | 317,469 | 982,197 | — | (154,692 | ) | (53 | ) | 1,144,921 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | 134,369 | 3,723 | — | 6,243 | 1,471 | 145,806 | ||||||||||||||||||
Cash and Cash Equivalents, beginning of period | 1,334 | — | — | 137 | (1,471 | ) | — | |||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 135,703 | $ | 3,723 | $ | — | $ | 6,380 | $ | — | $ | 145,806 |
155
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Year Ended June 30, 2013 (Restated) | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 180,783 | $ | 201,691 | $ | 343,015 | $ | 159,066 | $ | (703,772 | ) | $ | 180,783 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 359,819 | 3,972 | — | 363,791 | ||||||||||||||||||
Deferred income tax expense | (7,297 | ) | 31,556 | — | (4,537 | ) | — | 19,722 | ||||||||||||||||
Change in derivative financial instruments | — | 20,885 | — | (34 | ) | — | 20,851 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 30,885 | — | — | 30,885 | ||||||||||||||||||
Loss from equity method investees | (175,218 | ) | (345,178 | ) | — | (177,366 | ) | 703,772 | 6,010 | |||||||||||||||
Amortization and write-off of debt issuance costs and other | — | 6,857 | — | 41 | — | 6,898 | ||||||||||||||||||
Stock-based compensation | 3,504 | — | — | — | 1 | 3,505 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | — | 14,422 | (13,156 | ) | 424 | — | 1,690 | |||||||||||||||||
Prepaid expenses and other current assets | 8,772 | 2,865 | 760 | 103 | (1 | ) | 12,499 | |||||||||||||||||
Settlement of asset retirement obligations | — | — | (41,939 | ) | — | — | (41,939 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | 15,437 | (284,087 | ) | 269,560 | 79,024 | (46,481 | ) | 33,453 | ||||||||||||||||
Net Cash Provided by (Used in) Operating Activities | 25,981 | (350,989 | ) | 948,944 | 60,693 | (46,481 | ) | 638,148 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (161,164 | ) | — | — | (161,164 | ) | ||||||||||||||||
Capital expenditures | — | (17,144 | ) | (787,774 | ) | (11,187 | ) | — | (816,105 | ) | ||||||||||||||
Change in equity method investments | (4,010 | ) | — | — | (16,693 | ) | 4,010 | (16,693 | ) | |||||||||||||||
Intercompany investment | — | — | — | (41,000 | ) | 41,000 | — | |||||||||||||||||
Other | — | — | (6 | ) | (35 | ) | — | (41 | ) | |||||||||||||||
Net Cash Used in (Provided by) Investing Activities | (4,010 | ) | (17,144 | ) | (948,944 | ) | (68,915 | ) | 45,010 | (994,003 | ) | |||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 7,021 | — | — | — | — | 7,021 | ||||||||||||||||||
Repurchase of company common stock | — | — | — | (58,666 | ) | — | (58,666 | ) | ||||||||||||||||
Dividends to shareholders – common | (25,992 | ) | — | — | — | — | (25,992 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (11,496 | ) | — | — | — | — | (11,496 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 1,571,061 | — | 5,490 | — | 1,576,551 | ||||||||||||||||||
Payments on long-term debt | — | (1,243,545 | ) | — | (303 | ) | — | (1,243,848 | ) | |||||||||||||||
Debt issuance costs | — | (4,777 | ) | — | (28 | ) | — | (4,805 | ) | |||||||||||||||
Other | — | — | — | 3 | — | 3 | ||||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (30,467 | ) | 322,739 | — | (53,504 | ) | — | 238,768 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | (8,496 | ) | (45,394 | ) | — | (61,726 | ) | (1,471 | ) | (117,087 | ) | |||||||||||||
Cash and Cash Equivalents, beginning of period | 9,830 | 45,394 | — | 61,863 | — | 117,087 | ||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 1,334 | $ | — | $ | — | $ | 137 | $ | (1,471 | ) | $ | — |
156
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED JUNE 30, 2015
Note 25 — Supplemental Guarantor Information – (continued)
Restated Quarterly Financial Statements
Restated Quarterly Financial Statements for the Three Months Ended September 30, 2014
ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS
(In thousands, except share information)
(Unaudited)
September 30, 2014 (Restated) | June 30, 2014 (Restated) | |||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 119,500 | $ | 145,806 | ||||
Accounts receivable | ||||||||
Oil and natural gas sales | 145,821 | 167,075 | ||||||
Joint interest billings | 14,426 | 12,898 | ||||||
Other | 5,615 | 5,438 | ||||||
Prepaid expenses and other current assets | 64,631 | 72,530 | ||||||
Deferred income taxes | 24,587 | 52,587 | ||||||
Derivative financial instruments | 23,815 | 1,425 | ||||||
Total Current Assets | 398,395 | 457,759 | ||||||
Property and Equipment | ||||||||
Oil and natural gas properties, net – full cost method of accounting, including $1,167.6 million and $1,165.7 million of unevaluated properties not being amortized at September 30, 2014 and June 30, 2014, respectively | 6,542,079 | 6,427,263 | ||||||
Other property and equipment, net | 23,400 | 19,760 | ||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 6,565,479 | 6,447,023 | ||||||
Other Assets | ||||||||
Goodwill | 329,293 | 329,293 | ||||||
Derivative financial instruments | 6,713 | 3,035 | ||||||
Equity investments | 40,320 | 40,643 | ||||||
Restricted Cash | 325 | 6,350 | ||||||
Other assets and debt issuance costs, net of accumulated amortization | 60,845 | 57,394 | ||||||
Total Other Assets | 437,496 | 436,715 | ||||||
Total Assets | $ | 7,401,370 | $ | 7,341,497 | ||||
LIABILITIES | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 472,108 | $ | 417,776 | ||||
Accrued liabilities | 115,509 | 133,526 | ||||||
Notes payable | 19,368 | 21,967 | ||||||
Asset retirement obligations | 79,614 | 79,649 | ||||||
Derivative financial instruments | 1,446 | 31,957 | ||||||
Current maturities of long-term debt | 15,612 | 15,020 | ||||||
Total Current Liabilities | 703,657 | 699,895 | ||||||
Long-term debt, less current maturities | 3,800,417 | 3,744,624 | ||||||
Deferred income taxes | 655,338 | 666,969 | ||||||
Asset retirement obligations | 482,339 | 480,185 | ||||||
Derivative financial instruments | — | 4,306 | ||||||
Other liabilities | 8,009 | 10,958 | ||||||
Total Liabilities | 5,649,760 | 5,606,937 | ||||||
Commitments and Contingencies (Note 17) | ||||||||
Stockholders’ Equity | ||||||||
Preferred stock, $0.001 par value, 7,500,000 shares authorized at September 30, 2014 and June 30, 2014 | ||||||||
7.25% Convertible perpetual preferred stock, 8,000 shares issued and outstanding at September 30, 2014 and June 30, 2014 | — | — | ||||||
5.625% Convertible perpetual preferred stock, 812,760 shares issued and outstanding at September 30, 2014 and June 30, 2014 | 1 | 1 | ||||||
Common stock, $0.005 par value, 200,000,000 shares authorized and 93,867,405 and 93,719,570 shares issued and outstanding at September 30, 2014 and June 30, 2014, respectively | 469 | 468 | ||||||
Additional paid-in capital | 1,841,457 | 1,837,462 | ||||||
Accumulated deficit | (90,317 | ) | (103,371 | ) | ||||
Total Stockholders’ Equity | 1,751,610 | 1,734,560 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 7,401,370 | $ | 7,341,497 |
See accompanying Notes to Consolidated Financial Statements
157
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share information)
(Unaudited)
Three Months Ended September 30, | ||||||||
2014 (Restated) | 2013 (Restated) | |||||||
Revenues | ||||||||
Crude oil sales | $ | 370,155 | $ | 290,966 | ||||
Natural gas sales | 34,561 | 32,584 | ||||||
Gain (loss) on derivative financial instruments | 56,725 | (30,403 | ) | |||||
Total Revenues | 461,441 | 293,147 | ||||||
Costs and Expenses | ||||||||
Lease operating | 142,585 | 85,763 | ||||||
Production taxes | 3,093 | 1,398 | ||||||
Gathering and transportation | 9,188 | 5,345 | ||||||
Depreciation, depletion and amortization | 159,140 | 97,660 | ||||||
Accretion of asset retirement obligations | 12,819 | 7,326 | ||||||
General and administrative expense | 26,424 | 23,672 | ||||||
Total Costs and Expenses | 353,249 | 221,164 | ||||||
Operating Income | 108,192 | 71,983 | ||||||
Other Income (Expense) | ||||||||
Income (loss) from equity method investees | 959 | (2,107 | ) | |||||
Other income – net | 951 | 522 | ||||||
Interest expense | (66,263 | ) | (29,685 | ) | ||||
Total Other Expense | (64,353 | ) | (31,270 | ) | ||||
Income Before Income Taxes | 43,839 | 40,713 | ||||||
Income Tax Expense | 16,649 | 15,431 | ||||||
Net Income | 27,190 | 25,282 | ||||||
Preferred Stock Dividends | 2,872 | 2,873 | ||||||
Net Income Available for Common Stockholders | $ | 24,318 | $ | 22,409 | ||||
Earnings per Share | ||||||||
Basic | $ | 0.26 | $ | 0.30 | ||||
Diluted | $ | 0.24 | $ | 0.27 | ||||
Weighted Average Number of Common Shares Outstanding | ||||||||
Basic | 93,833 | 75,782 | ||||||
Diluted | 102,300 | 84,073 |
See accompanying Notes to Consolidated Financial Statements
158
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Three Months Ended September 30, | ||||||||
2014 (Restated) | 2013 (Restated) | |||||||
Cash Flows From Operating Activities | ||||||||
Net income | $ | 27,190 | $ | 25,282 | ||||
Adjustments to reconcile net income to net cash provided by | ||||||||
operating activities: | ||||||||
Depreciation, depletion and amortization | 159,140 | 97,660 | ||||||
Deferred income tax expense (benefit) | 16,369 | 12,574 | ||||||
Change in fair value of derivative financial instruments | (55,095 | ) | 27,505 | |||||
Accretion of asset retirement obligations | 12,819 | 7,326 | ||||||
Loss (income) from equity method investees | (959 | ) | 2,107 | |||||
Amortization and write-off of debt issuance costs and other | 2,744 | 1,455 | ||||||
Stock-based compensation | 1,779 | 3,532 | ||||||
Changes in operating assets and liabilities | ||||||||
Accounts receivable | 23,313 | (2,131 | ) | |||||
Prepaid expenses and other current assets | 7,661 | (6,270 | ) | |||||
Settlement of asset retirement obligations | (14,907 | ) | (18,063 | ) | ||||
Accounts payable and accrued liabilities | 23,896 | (43,078 | ) | |||||
Net Cash Provided by Operating Activities | 203,950 | 107,899 | ||||||
Cash Flows from Investing Activities | ||||||||
Acquisitions | (287 | ) | (15 | ) | ||||
Capital expenditures | (280,010 | ) | (198,358 | ) | ||||
Change in equity method investments | 1,282 | (16,694 | ) | |||||
Proceeds from the sale of properties | 6,947 | 1,748 | ||||||
Other | (80 | ) | (51 | ) | ||||
Net Cash Used in Investing Activities | (272,148 | ) | (213,370 | ) | ||||
Cash Flows from Financing Activities | ||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,217 | 3,267 | ||||||
Repurchase of company common stock | — | (35,210 | ) | |||||
Dividends to shareholders – common | (11,264 | ) | (9,096 | ) | ||||
Dividends to shareholders – preferred | (2,872 | ) | (2,873 | ) | ||||
Proceeds from long-term debt | 510,120 | 1,040,697 | ||||||
Payments on long-term debt | (454,042 | ) | (865,231 | ) | ||||
Debt issuance costs | (2,250 | ) | (8,720 | ) | ||||
Other | (17 | ) | (1 | ) | ||||
Net Cash Provided by Financing Activities | 41,892 | 122,833 | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (26,306 | ) | 17,362 | |||||
Cash and Cash Equivalents, beginning of period | 145,806 | — | ||||||
Cash and Cash Equivalents, end of period | $ | 119,500 | $ | 17,362 |
See accompanying Notes to Consolidated Financial Statements
159
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 1 — Organization and Summary of Significant Accounting Policies
Nature of Operations. Energy XXI Ltd (“Energy XXI”) was incorporated in Bermuda on July 25, 2005. With our principal operating subsidiary 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 in 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.
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to the Alternative Investment Market of the London Stock Exchange (“AIM”), to be effective any time on or before March 13, 2015.
References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.
Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany transactions have been eliminated in consolidation.
Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in this Form 10-K.
Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
Note 2 — Recent Accounting Pronouncements
In July 2013 the FASB issued Accounting Standards Update No. 2013-11,Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists (ASU-2013-11). ASU 2013-11 clarifies that an unrecognized tax benefit, or a portion of an unrecognized tax benefit, should be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such settlement is required or expected in the event the uncertain tax position is disallowed. In situations where a net operating loss carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset for such purpose, the unrecognized tax benefit should be presented in
160
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 2 — Recent Accounting Pronouncements – (continued)
the financial statements as a liability and should not be combined with deferred tax assets. ASU 2013-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013, with early adoption permitted. We have no unrecognized tax benefits as defined in the literature; as such, issuance of ASU 2013-11 has no effect on our consolidated financial position, results of operations or cash flows.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15,Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern, and to provide related footnote disclosures in certain circumstances. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.
Note 3 — Acquisitions and Dispositions
Black Elk Interest
On December 20, 2013, we closed on the acquisition of certain offshore Louisiana interests in West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for a total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013. We are the operator of these properties.
Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The acquisition of West Delta 30 Interests was accounted for under the acquisition method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):
Oil and natural gas properties – evaluated | $ | 15,821 | ||
Oil and natural gas properties – unevaluated | 6,586 | |||
Asset retirement obligations | (10,503 | ) | ||
Net working capital* | (1,500 | ) | ||
Cash paid | $ | 10,404 |
* | Net working capital includes payables. |
Walter Oil & Gas Corporation oil and gas properties interests acquisition
On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for a total cash consideration of approximately $22.8 million. This acquisition was effective as of January 1, 2014 and we are the operator of these properties.
161
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The acquisition of South Timbalier 54 Interests was accounted for under the acquisition method of accounting. Transaction, transition and integration costs associated with this acquisition were expensed as incurred. The following table presents the preliminary purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):
Oil and natural gas properties – evaluated | $ | 23,497 | ||
Asset retirement obligations | (705 | ) | ||
Cash paid | $ | 22,792 |
The fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions were measured using valuation techniques that convert future cash flows to a single discounted amount. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) the discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate.
Apache Joint Venture
On February 1, 2013, we entered into an Exploration Agreement (the “Exploration Agreement”) with Apache Corporation (“Apache”) to jointly participate in exploration of oil and gas pay sands associated with salt dome structures on the central GoM Shelf. We have a 25% participation interest in the Exploration Agreement, which expires on February 1, 2018.
The area of mutual interest under this Exploration Agreement includes several salt domes within a 135 block area. Our share of cost to acquire seismic data over a two-year seismic shoot phase is currently estimated to be approximately $37.5 million of which approximately $33.7 million was incurred through September 30, 2014. Drilling on the first well commenced in May 2013 on the southern flank of the salt dome, penetrating eight oil sands and one gas bearing sand. In February 2014 we commenced drilling an offset well which also encountered multiple hydrocarbon bearing sands. Presently both the wellbores have been suspended for future utility and we expect to complete 3D wide azimuth (“WAZ”) seismic data analysis in December 2014. As of September 30, 2014, our share of costs related to these wells was approximately $28.6 million.
Acquisition of EPL Oil & Gas, Inc. (“EPL”)
We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly-owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.
In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election”) and collectively the (“Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders
162
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares shown below, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash.
The following table summarizes the preliminary purchase price allocation for EPL as of June 3, 2014 (in thousands):
EPL Historical | Fair Value Adjustment | Total | ||||||||||||
(Unaudited) | ||||||||||||||
Current assets (excluding deferred income taxes) | $ | 301,592 | $ | 1,274 | $ | 302,866 | ||||||||
Oil and natural gas properties(a) | ||||||||||||||
Evaluated (Including net ARO assets) | 1,919,699 | 112,624 | 2,032,323 | |||||||||||
Unevaluated | 41,896 | 859,886 | 901,782 | |||||||||||
Other property and equipment | 7,787 | — | 7,787 | |||||||||||
Other assets | 16,227 | (9,002 | ) | 7,225 | ||||||||||
Current liabilities (excluding ARO) | (314,649 | ) | (2,058 | ) | (316,707 | ) | ||||||||
ARO (current and long-term) | (260,161 | ) | (13,211 | ) | (273,372 | ) | ||||||||
Debt (current and long-term) | (973,440 | ) | (52,967 | ) | (1,026,407 | ) | ||||||||
Deferred income taxes(b) | (118,359 | ) | (340,645 | ) | (459,004 | ) | ||||||||
Other long-term liabilities | (2,242 | ) | 797 | (1,445 | ) | |||||||||
Total fair value, excluding goodwill | 618,350 | 556,698 | 1,175,048 | |||||||||||
Goodwill(c),(d) | — | 329,293 | 329,293 | |||||||||||
Less cash acquired | — | — | 206,075 | |||||||||||
Total purchase price | $ | 618,350 | $ | 885,991 | $ | 1,298,266 |
(a) | EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy. |
(b) | Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit). |
(c) | At September 30, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was unnecessary, and no goodwill impairment was recognized. |
163
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
(d) | On April 2, 2013, EPL sold certain shallow water GoM shelf oil and natural gas interests located within the non-operated Bay March and field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling to approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million; accordingly the June 30, 2014 comparative information is retrospectively adjusted to increase the value of goodwill. |
Costs associated with the EPL Acquisition totaled $13.6 million in the year ended June 30, 2014. For the quarter ended September 30, 2014, our Consolidated Statement of Operations includes EPL’s operating revenues and net income of $194.1 million and $26.2 million.
In accordance with the acquisition method of accounting, the purchase price from our acquisition of EPL has been allocated to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates, and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed has been recorded as goodwill. Goodwill recorded in connection with the acquisition is not deductible for income tax purposes.
The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.
The fair value measurements of the oil and natural gas properties and the asset retirement obligations included in other long-term liabilities were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value measurement of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.
Goodwill arose subsequent to the EPL Acquisition primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative functions by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, that enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets.
Sales of Oil and Natural Gas properties interests
On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned indirect subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI
164
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million.
On June 3, 2014, EXXI GOM, closed on the sale of its 100% interests in South Pass 49 field to EPL, which is our wholly owned indirect subsidiary, for cash consideration of approximately $230 million. As this transaction is between our two wholly owned indirect subsidiaries, there is no impact on a consolidated basis to our revenues and expenses or the full cost pool related to this transaction.
Note 4 — Property and Equipment
Property and equipment consists of the following (in thousands):
September 30, 2014 (Restated) | June 30, 2014 (Restated) | |||||||
Oil and gas properties | ||||||||
Proved properties | $ | 8,518,475 | $ | 8,247,352 | ||||
Less: accumulated depreciation, depletion, amortization and impairment | 3,144,033 | 2,985,790 | ||||||
Proved properties, net | 5,374,442 | 5,261,562 | ||||||
Unevaluated properties | 1,167,637 | 1,165,701 | ||||||
Oil and gas properties, net | 6,542,079 | 6,427,263 | ||||||
Other property and equipment | 44,051 | 39,272 | ||||||
Less: accumulated depreciation | 20,651 | 19,512 | ||||||
Other property and equipment, net | 23,400 | 19,760 | ||||||
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment | $ | 6,565,479 | $ | 6,447,023 |
The Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions, exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with unproved properties are transferred to evaluated properties upon the earlier of 1) when a determination is made whether there are any proved reserves related to the properties, or 2) amortized over a period of time of not more than four years.
Exploratory wells in progress include $197.7 million in costs related to our participation with Freeport-McMoRan, Inc. who operates several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico. Activities related to certain of these well operations are controlled by the operator and these wells may have continued drilling and completion activities or, may require development of specialized equipment necessary to complete and test these wells for production.
165
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 4 — Property and Equipment – (continued)
As of September 30, 2014, the costs associated with our major projects and their status was as follows(in millions):
Project Name | Cost | Status | ||||||
Davy Jones Facilities | $ | 22.0 | Facilities cost in Davy Jones field for well operations. | |||||
Davy Jones Offset Appraisal Well | 70.2 | Davy Jones Offset Appraisal Well is awaiting test of Wilcox sands. | ||||||
Blackbeard East | 51.4 | Plans to complete into the Miocene Sands in late 2015. | ||||||
Lomond North | 54.1 | Completion operations in progress to test lower Wilcox and Cretaceous objectives | ||||||
Total | $ | 197.7 |
Note 5 — Equity Method Investments
20% interest in Energy XXI M21K, LLC
We own a 20% interest in EXXI M21K, which engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).
Since its inception in February 2012, M21K has completed three acquisitions for aggregate cash consideration of approximately $284.1 million. In July 2012, it acquired oil and gas interests from EP Energy E&P Company, L.P. for approximately $80.4 million. In August 2013, it acquired oil and gas interests from LLOG Exploration Offshore, L.L.C. for approximately $80.8 million and in April 2014, it acquired oil and gas interests from EXXI GOM for approximately $122.9 million.
EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K related to the three acquisitions noted above. Further, Energy XXI Gulf Coast, Inc. (“EGC”), an indirect wholly owned subsidiary of Energy XXI receives a management fee from M21K for providing administrative assistance in carrying out its operations. See Note 14 — Related Party Transactions within these quarterly consolidated financial statements.
The provisions of the M21K Limited Liability Company Agreement (“LLC Agreement”) provide that M21K can make acquisitions subject to the commitment of its partners. While it is envisioned that M21K will be sold eventually to a third party to monetize returns from the investments, the M21K LLC Agreement does provide for a put and a call that can occur starting July 19, 2016; subject to an earlier option if there is a change of control of Energy XXI.
As of September 30, 2014, our investment in EXXI M21K was approximately $40.3 million and for the three months ended September 30, 2014 and 2013, we had equity income of $1.0 million and had incurred an equity loss of $0.9 million, respectively.
80% interest in Ping Energy XXI Limited (“Ping Energy”)
On October 18, 2013, Energy XXI International Limited (“EXXI International”) amended the Joint Development Agreement (“JDA”) and increased its ownership interest to 80% from 49% in Ping Energy, subsequent to which all the operations in Ping Energy were consolidated in our financial statements, effective October 1, 2013. In January 2014, EXXI International terminated the JDA with Ping Energy and is in the process of dissolving Ping Energy.
166
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 5 — Equity Method Investments – (continued)
Subsequent to our EPL Acquisition, as disclosed in Note 3 — Acquisitions and Dispositions of Notes to Consolidated Financial Statements in these quarterly consolidated financial statements, we have no present intention to pursue any international opportunities to acquire exploratory, development or producing oil and natural gas properties.
Note 6 — Long-Term Debt
Long-term debt consists of the following (in thousands):
September 30, 2014 | June 30, 2014 | |||||||
Revolving Credit Facility | $ | 748,264 | $ | 689,000 | ||||
8.25% Senior Notes due 2018 | 510,000 | 510,000 | ||||||
6.875% Senior Notes due 2024 | 650,000 | 650,000 | ||||||
3.0% Senior Convertible Notes due 2018 | 400,000 | 400,000 | ||||||
7.5% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
7.75% Senior Notes due 2019 | 250,000 | 250,000 | ||||||
9.25% Senior Notes due 2017 | 750,000 | 750,000 | ||||||
4.14% Promissory Note due 2017 | 4,670 | 4,774 | ||||||
Debt premium, 8.25% Senior Notes due 2018(1) | 38,033 | 40,566 | ||||||
Original issue discount, 3.0% Senior Convertible Notes due 2018 | (54,259 | ) | (57,014 | ) | ||||
Derivative instruments premium financing | 18,044 | 21,000 | ||||||
Capital lease obligations | 1,277 | 1,318 | ||||||
Total debt | 3,816,029 | 3,759,644 | ||||||
Less current maturities | 15,612 | 15,020 | ||||||
Total long-term debt | $ | 3,800,417 | $ | 3,744,624 |
(1) | Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition. |
Maturities of long-term debt as of September 30, 2014 are as follows (in thousands):
Twelve Months Ended September 30, | ||||
2015 | $ | 15,612 | ||
2016 | 4,227 | |||
2017 | 755 | |||
2018 | 2,049,694 | |||
2019 | 595,741 | |||
Thereafter | 1,150,000 | |||
Total | $ | 3,816,029 |
Revolving Credit Facility
The second amended and restated first lien credit agreement (“First Lien Credit Agreement”) was entered into by EGC in May 2011 and underwent its Ninth Amendment on September 5, 2014. This facility, as amended, has a borrowing base of $1,500 million and lender commitments of $1,700 million and matures on April 9, 2018, provided that the facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank
167
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The revolving credit facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions. The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, EGC may not permit the following: (a) EGC’s total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, (c) EGC’s current ratio to be less than 1.0 to 1.0, and (d) EGC’s secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in our First Lien Credit Agreement). In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.
As of September 30, 2014, EGC was in compliance with all covenants and had $748.3 million in borrowings and $226 million in letters of credit issued under our First Lien Credit Agreement.
8.25% Senior Notes Due 2018
On June 3, 2014, EGC assumed the 8.25% senior notes due 2018 (the “8.25% Senior Notes”) in the EPL Acquisition, which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of consents from the requisite holders of the 8.25% Senior Notes in accordance with the terms and conditions of the Consent Solicitation Statement dated April 7, 2014, pursuant to which we had solicited consents (the “Consent Solicitation”) from the holders of the 8.25% Senior Notes to make certain proposed amendments to certain definitions set forth in the Indenture (the “Proposed COC Amendments”), as reflected in the Supplemental Indenture. The Consent Solicitation was made as permitted by the merger agreement. On April 18, 2014, we had received valid consents from holders of an aggregate principal amount of $484.1 million of the 8.25% Senior Notes and that those consents had not been revoked prior to the consent time. As a result, the requisite holders of the 8.25% Senior Notes had consented to the Proposed COC Amendments, upon the terms and subject to the conditions set forth in the Consent Solicitation Statement. Accordingly, EPL, the guarantors party thereto and the Trustee entered into the Supplemental Indenture. Subject to the terms and conditions set forth in the Statement, we paid an aggregate cash payment equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents to the Proposed COC Amendments were validly delivered and unrevoked. The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.
EGC believes that the fair value of the $510 million of 8.25% Senior Notes outstanding as of September 30, 2014 was $519.1 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.
168
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
6.875% Senior Notes Due 2024
On May 27, 2014, EGC issued $650 million face value of 6.875%, unsecured senior notes due March 15, 2024 at par (the “6.875% Senior Notes”). Presently, the 6.875% Senior Notes are not registered under the Securities Act of 1933, as amended (the “Securities Act”), however EGC and its guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes. EGC incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and will be amortized over the life of the 6.875% Senior Notes.
On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption shall be made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 6.875% Senior Notes.
The indenture governing the 6.875% Senior Notes will, among other things, limit EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
EGC believes that the fair value of the $650 million of 6.875% Senior Notes outstanding as of September 30, 2014 was $617.5 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.
3.0% Senior Convertible Notes Due 2018
On November 18, 2013, the Company sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Company incurred underwriting and direct offering costs of $7.6 million which have been capitalized and will be amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and thus the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
169
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
Upon conversion, the Company will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the Company satisfies its conversion obligation solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will not receive any cash payment representing accrued and unpaid interest. Instead, interest will be paid by the cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be, upon conversion of a convertible note.
If holders elect to convert the notes in connection with certain fundamental change transactions described in the indenture governing the 3.0% Senior Convertible Notes, the Company will increase the conversion rate by a number of additional shares determined by reference to the provisions contained in the indenture governing the 3.0% Senior Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of common stock in, such make-whole fundamental change. If holders of common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.
If the Company undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require the Company to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.
For accounting purposes, the $400 million aggregate principal amount of 3.0% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3.0% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the $63.4 million original issue discount will be amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.
The Company believes that the fair value of the $400 million of 3.0% Senior Convertible Notes, net of the equity conversion feature, as of September 30, 2014 was $326.5 million based on quoted prices. The market is not an active market; therefore, the fair value is classified within Level 2.
7.5% Senior Notes Due 2021
On September 26, 2013, EGC issued $500 million face value of 7.5%, unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”). In April 2014, we filed Amendment No. 1 to the registration statement for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes with the SEC. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and will be amortized over the life of the 7.5% Senior Notes.
170
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of the certain asset sales under specified circumstances each of which as defined in the indenture governing the 7.5% Senior Notes.
The indenture governing the 7.5% Senior Notes limits, among other things, EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
EGC believes that the fair value of the $500 million of 7.5% Senior Notes outstanding as of September 30, 2014 was $494.3 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.
9.25% Senior Notes Due 2017
On December 17, 2010, EGC issued $750 million face value of 9.25%, unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act, on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.
The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. The 9.25% Senior Notes also provide for the redemption of up to 35% of the 9.25% Senior Notes outstanding at 109.25% prior to December 15, 2013 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 9.25% Senior Notes.
EGC believes that the fair value of the $750 million of 9.25% Senior Notes outstanding as of September 30, 2014 was $775.8 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.
7.75% Senior Notes Due 2019
On February 25, 2011, EGC issued $250 million face value of 7.75%, unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.
171
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. The 7.75% Senior Notes also provide for the redemption of up to 35% of the 7.75% Senior Notes outstanding at 107.75% prior to June 15, 2014 with the proceeds from any equity raised. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and will be amortized over the life of the notes.
EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances each of which as defined in the indenture governing the 7.75% Senior Notes.
EGC believes that the fair value of the $250 million of 7.75% Senior Notes outstanding as of September 30, 2014 was $250.4 million based on quoted prices and the market is not an active market; therefore, the fair value is classified within Level 2.
Guarantee of Securities Issued by EGC
Our indirect, wholly-owned subsidiary, EGC, is the issuer of each of the 6.875% Senior Notes, 7.5% Senior Notes, 9.25% Senior Notes and 7.75% Senior Notes, which are fully and unconditionally guaranteed by us and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries. We and our subsidiaries, other than EGC, do not have significant independent assets or operations. EGC is permitted to make dividends and other distributions subject to certain limitations as more fully disclosed in this note above under the caption “Revolving Credit Facility.”
4.14% Promissory Note
In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity, in October 2017. This note carries an interest rate of 4.14% per annum.
Derivative Instruments Premium Financing
We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedges are done with lenders under our revolving credit facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the revolving credit facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value net of derivative instrument premium financing. As of September 30, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $18 million and $21 million, respectively.
172
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 6 — Long-Term Debt – (continued)
Interest Expense
For the three months ended September 30, 2014 and 2013, interest expense consisted of the following (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Revolving Credit Facility | $ | 6,893 | $ | 5,219 | ||||
8.25% Senior Notes due 2018 | 10,519 | — | ||||||
6.875% Senior Notes due 2024 | 11,172 | — | ||||||
3.0% Senior Convertible Notes due 2018 | 3,025 | — | ||||||
7.50% Senior Notes due 2021 | 9,375 | 521 | ||||||
7.75% Senior Notes due 2019 | 4,844 | 4,844 | ||||||
9.25% Senior Notes due 2017 | 17,344 | 17,344 | ||||||
4.14% Promissory Note due 2017 | 52 | 52 | ||||||
Amortization of debt issue cost – Revolving Credit Facility | 977 | 806 | ||||||
Amortization of fair value premium – 8.25% Senior Notes due 2018 | (2,534 | ) | — | |||||
Amortization of debt issue cost – 6.875% Senior Notes due 2024 | 281 | — | ||||||
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 | 2,755 | — | ||||||
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 | 353 | — | ||||||
Amortization of debt issue cost – 7.50% Senior Notes due 2021 | 263 | — | ||||||
Amortization of debt issue cost – 7.75% Senior Notes due 2019 | 97 | 97 | ||||||
Amortization of debt issue cost – 9.25% Senior Notes due 2017 | 552 | 552 | ||||||
Derivative instruments financing and other | 295 | 250 | ||||||
$ | 66,263 | $ | 29,685 |
Note 7 — Notes Payable
In November 2012, we entered into a note with AFCO Credit Corporation to finance a portion of our director and officer insurance premiums. The note was for a total face amount of $0.6 million and bore interest at an annual rate of 1.774%. The note matured and was repaid on October 23, 2013.
In May 2013, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $24.8 million and bore interest at an annual rate of 1.623%. The note matured and was repaid on April 26, 2014.
On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of September 30, 2014 was $16.0 million.
On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015. The balance outstanding as of September 30, 2014 was $3.4 million.
173
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 8 — Asset Retirement Obligations
The following table describes the changes to our asset retirement obligations (in thousands):
Balance at June 30, 2014 | $ | 559,834 | ||
Liabilities incurred and true-up to liabilities settled | 5,372 | |||
Liabilities settled | (14,907 | ) | ||
Liabilities sold | (1,165 | ) | ||
Accretion expense | 12,819 | |||
Total balance at September 30, 2014 | 561,953 | |||
Less current portion | 79,614 | |||
Long-term balance at September 30, 2014 | $ | 482,339 |
Note 9 — Derivative Financial Instruments
We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue in the consolidated statements of operations.
With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.
Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.
The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.
174
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 9 — Derivative Financial Instruments – (continued)
Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent.
As of September 30, 2014, we had the following net open crude oil derivative positions:
Weighted Average Contract Price | ||||||||||||||||||||||||||||
Swaps | Collars/Put Spreads | |||||||||||||||||||||||||||
Remaining Contract Term | Type of Contract | Index | Volumes (MBbls) | Fixed Price | Sub Floor | Floor | Ceiling | |||||||||||||||||||||
October 2014 – December 2014 | Three-Way Collars | Oil-Brent-IPE | 490 | $ | 68.44 | $ | 88.44 | $ | 128.56 | |||||||||||||||||||
October 2014 – December 2014 | Put Spreads | Oil-Brent-IPE | 109 | 66.43 | 86.43 | |||||||||||||||||||||||
October 2014 – December 2014 | Collars | Oil-Brent-IPE | 184 | 90.00 | 108.38 | |||||||||||||||||||||||
October 2014 – December 2014 | Put Spreads | NYMEX-WTI | 310 | 70.00 | 90.00 | |||||||||||||||||||||||
October 2014 – December 2014 | Three-Way Collars | NYMEX-WTI | 610 | 70.00 | 90.00 | 137.20 | ||||||||||||||||||||||
October 2014 – December 2014 | Swaps | ARGUS-LLS | 712 | $ | 91.95 | |||||||||||||||||||||||
January 2015 – December 2015 | Three-Way Collars | Oil-Brent-IPE | 3,650 | 71.00 | 91.00 | 113.75 | ||||||||||||||||||||||
January 2015 – December 2015 | Swaps | Oil-Brent-IPE | 548 | 97.70 | ||||||||||||||||||||||||
January 2015 – December 2015 | Collars | ARGUS-LLS | 1,825 | 80.00 | 123.38 | |||||||||||||||||||||||
January 2015 – December 2015 | Put Spreads | NYMEX-WTI | 2,728 | 89.18 |
As of September 30, 2014, we had the following net open natural gas derivative positions:
Weighted Average Contract Price | ||||||||||||||||||||||||||||
Swaps | Collars/Put Spreads | |||||||||||||||||||||||||||
Remaining Contract Term | Type of Contract | Index | Volumes (MMBtu) | Fixed Price | Sub Floor | Floor | Ceiling | |||||||||||||||||||||
October 2014 – December 2014 | Three-Way Collars | NYMEX-HH | 4,197 | $ | 3.36 | $ | 4.00 | $ | 4.60 | |||||||||||||||||||
October 2014 – December 2014 | Put Spreads | NYMEX-HH | 403 | 3.25 | 4.00 | |||||||||||||||||||||||
October 2014 – December 2014 | Swaps | NYMEX-HH | 460 | $ | 4.01 | |||||||||||||||||||||||
January 2015 – December 2015 | Swaps | NYMEX-HH | 1,570 | 4.31 |
The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):
Asset Derivative Instruments | Liability Derivative Instruments | |||||||||||||||||||||||||||||||
September 30, 2014 | June 30, 2014 | September 30, 2014 | June 30, 2014 | |||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||||||||||||||||||
Derivative financial instruments | Current | $ | 31,138 | Current | $ | 17,380 | Current | $ | 8,769 | Current | $ | 47,912 | ||||||||||||||||||||
Non-Current | 9,110 | Non-Current | 9,595 | Non-Current | 2,397 | Non-Current | 10,866 | |||||||||||||||||||||||||
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement | 40,248 | 26,975 | 11,166 | 58,778 | ||||||||||||||||||||||||||||
Derivative financial instruments | Current | (7,323 | ) | Current | (15,955 | ) | Current | (7,323 | ) | Current | (15,955 | ) | ||||||||||||||||||||
Non-Current | (2,397 | ) | Non-Current | (6,560 | ) | Non-Current | (2,397 | ) | Non-Current | (6,560 | ) | |||||||||||||||||||||
Gross amounts offset in Balance Sheets | (9,720 | ) | (22,515 | ) | (9,720 | ) | (22,515 | ) | ||||||||||||||||||||||||
Net amounts presented in Balance Sheets | Current | 23,815 | Current | 1,425 | Current | 1,446 | Current | 31,957 | ||||||||||||||||||||||||
Non-Current | 6,713 | Non-Current | 3,035 | Non-Current | — | Non-Current | 4,306 | |||||||||||||||||||||||||
$ | 30,528 | $ | 4,460 | $ | 1,446 | $ | 36,263 |
175
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 9 — Derivative Financial Instruments – (continued)
The following table presents information about the components of the gain (loss) on derivative instruments (in thousands).
Gain (loss) on derivative financial instruments | Three Months Ended September 30, | |||||||
2014 | 2013 | |||||||
Cash Settlements, net of amortization of purchased put premiums | $ | (1,734 | ) | $ | (2,898 | ) | ||
Proceeds from monetizations, net | 3,364 | — | ||||||
Change in fair value | 55,095 | (27,505 | ) | |||||
Total gain (loss) on derivative financial instruments | $ | 56,725 | $ | (30,403 | ) |
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices, and could incur a loss. At September 30, 2014, we had no deposits for collateral with our counterparties.
Note 10 — Income Taxes
We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. Currently, our estimated annual effective tax rate is approximately 38%. The variance from the U.S. statutory rate of 35% is primarily due to non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit and the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses). Our Bermuda companies continue to report a tax provision reflecting accrued 30% U.S. withholding tax required on any interest (and interest equivalent) payments made from the U.S. companies to the Bermuda companies. We have accrued an additional withholding obligation of $2.6 million for the three months ended September 30, 2014.
Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and Gulf Coast will not file a combined nor consolidated Louisiana income tax return. Our valuation allowance of $22.5 million relates to Energy XXI’s separate company Louisiana net operating loss (“NOL”) carryovers that we do not currently believe, on a more likely-than-not basis, will be realized in future years due to the company’s current focus on offshore operations. No valuation allowance has been (or is expected to be) recorded with respect to any Louisiana NOLs generated by EPL, or on consolidated U.S. federal NOL carryovers. Management believes that there is sufficient future taxable income available arising from the future reversal of existing temporary differences recorded due to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed.
In this quarter, we made a cash withholding tax payment of $0.3 million on management fees paid to our Bermuda entities. While we have not made a cash income tax payment during this quarter, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We expect any AMT payment to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.
176
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 10 — Income Taxes – (continued)
On May 13, 2014, the U.S. Internal Revenue Service (“IRS”) notified the Company of their intent to examine the Company’s U.S. federal income tax return (Form 1120) for the year ended June 30, 2013. Subsequently, on October 16, 2014, the Company was notified by the IRS that their review was complete and that they were proposing no changes for the tax year ended June 30, 2013. While the Company is awaiting final, formal notification from the IRS as to this conclusion, it believes that it has adequately provided for income taxes and any related interest for all open tax years.
Note 11 — Stockholders’ Equity
Common Stock
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”). Our common stock trades on the NASDAQ and on the Alternative Investment Market of the London Stock Exchange (“AIM”) under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to the Alternative Investment Market of the London Stock Exchange (“AIM”), to be effective any time on or before March 13, 2015.
We paid quarterly cash dividends of $0.12 per share to holders of our common stock on June 14, 2013, September 13, 2013, December 13, 2013, March 14, 2014, June 13, 2014 and September 12, 2014, to shareholders of record on May 31, 2013, August 30, 2013, November 29, 2013, February 28, 2014, May 30, 2014 and August 29, 2014, respectively.
Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, through September 30, 2014, we paid $166.8 million to repurchase 6,639,363 shares of our common stock at a weighted average price per share, excluding fees, of $25.14. As of September 30, 2014, $83.2 million remains available for repurchase under the share repurchase program.
In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, one of the Company’s wholly-owned subsidiary 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.
In February 2014, we retired 2,087,126 shares of our common stock, resulting in 7,329,100 shares of common stock being held in treasury. The entire 7,329,100 shares of common stock in treasury were reissued on June 3, 2014 as part of our common stock issued to EPL stockholders upon merger.
As discussed in Note 6 — Long-Term Debt in the Notes to these quarterly consolidated financial statements, in November 2013, we sold $400 million of 3.0% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3.0% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital.
As discussed in Note 3 — Acquisitions and Dispositions in the Notes to these quarterly consolidated financial statements, upon closing of the EPL Acquisition, we issued 23,320,955 of our common stock, including the reissue of our common stock held in treasury, as noted above, towards the stock component of the EPL purchase price.
177
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 11 — Stockholders’ Equity – (continued)
Preferred Stock
Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.
Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year.
Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash or, where freely transferable by any non-affiliate recipient thereof, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of our common stock as determined on the second trading day immediately prior to the record date for such dividend.
The 5.625% preferred stock is callable beginning December 15, 2013 if the trading price exceeds $32.45 per share for 20 of 30 consecutive trading days.
Conversion of Preferred Stock
During the three months ended September 30, 2013, we canceled and converted a total of 28 shares of our 5.625% Preferred Stock into a total of 281 shares of common stock using a conversion rate of 10.0147 common shares per preferred share.
Note 12 — Supplemental Cash Flow Information
The following table represents our supplemental cash flow information (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Cash paid for interest | $ | 41,827 | $ | 5,766 | ||||
Cash paid for income taxes | 280 | 2,856 |
The following table represents our non-cash investing and financing activities (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Financing of insurance premiums | $ | 3,358 | $ | 2,355 | ||||
Derivative instruments premium financing | — | 698 | ||||||
Additions to property and equipment by recognizing asset retirement obligations | 4,207 | 14,151 |
Note 13 — Employee Benefit Plans
The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We maintain an incentive and retention program for our employees. Participation shares (or “Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Restricted Stock Units.
178
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 13 — Employee Benefit Plans – (continued)
Performance Units
For fiscal 2014, 2013 and 2012, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.
Time-Based Performance Units. The amount due the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal year 2012, 2013 and 2014 grants the initial stock price was $33.20, $24.50 and $22.48, respectively.
TSR Performance-Based Units. For each 2014, 2013 and 2012 TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.
In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period for the 2014, 2013 and 2012 grants.
At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash. The July 21, 2014 vesting of the July 21, 2013, 2012 and 2011 Performance Unit awards were settled 50% in common stock and future vesting of the Performance Units may be settled in stock at the discretion of our board of directors. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.
Changes for Fiscal 2015 Performance Unit Grants. For the performance unit awards granted in fiscal 2015, the Remuneration Committee of the Board of Directors has determined to change the performance measure within the long-term incentive plan from absolute TSR to relative TSR compared to a performance peer group. Under this plan, executives will receive no payout for TSR performance below the 25th percentile, a 50% payout for TSR performance at the 25th percentile, a 100% payout for TSR performance at the median, and 200% payout for performance at or above the 75th percentile. Payouts under this plan will be capped at target if absolute total shareholder return is negative. In addition, the Remuneration Committee has decided to eliminate the use of a $5 notional unit and instead will denominate units based on the stock price on the grant date. The Remuneration Committee also decided to eliminate the make-up feature for the fiscal 2015 awards. The awards for fiscal 2015 have continued to be granted 25% in the form of Time-Based Performance Unit awards and 75% in the form of TSR Performance-Based Unit awards.
We recognized compensation expense (benefit) related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Restricted Stock Units | $ | 970 | $ | 5,436 | ||||
Performance Units | (5,175 | ) | 12,352 | |||||
Total compensation expense (benefit) recognized | $ | (4,205 | ) | $ | 17,788 |
179
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 13 — Employee Benefit Plans – (continued)
As of September 30, 2014, we had 1,782,704 unvested Restricted Stock Units and 3,199,250 unvested $5 Performance Based Units and 1,025,000 stock price valued Performance Based Units.
Stock Purchase Plan
Effective as of July 1, 2008, we adopted the Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan (“2008 Purchase Plan”), which allows eligible employees, directors, and other service providers of ours and our subsidiaries to purchase from us shares of our common stock that have either been purchased by us on the open market or that have been newly issued by us. During the three months ended September 30, 2014 and 2013, we issued 93,776 shares and 117,902 shares, respectively, under the 2008 Purchase Plan.
In November 2008 we adopted the Energy XXI Services, LLC Employee Stock Purchase Plan (the “Employee Stock Purchase Plan”) which allows employees to purchase common stock at a 15% discount from the lower of the common stock closing price on the first or last day of the offering period. The current offering period is from July 1, 2014 to December 31, 2014. We use Black-Scholes Model to determine fair value, which incorporates assumptions to value stock-based awards. The shares issuable under Employee Stock Purchase Plan are included in calculating diluted earnings per share, if dilutive. As of September 30, 2014 we had $196,000 in unrecognized compensation. The compensation expense recognized and shares issued under Employee Stock Purchase Plan were as follows (in thousands, except for shares):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Compensation expense | $ | 241 | $ | 196 | ||||
Shares issued | — | — |
Stock Options
In September 2008, our Board of Directors granted 300,000 stock options to certain officers. These options to purchase our common stock were granted with an exercise price of $17.50 per share. These options vested over a three year period and may be exercised any time prior to September 10, 2018. We utilized the Black-Scholes model to determine the fair value of these stock options. As of September 30, 2014, 100,000 of the vested options have been exercised and the remaining 200,000 vested options have not been exercised.
Defined Contribution Plans
Our employees are covered by a discretionary noncontributory profit sharing plan. The plan provides for annual employer contributions that can vary from year to year. We also sponsor a qualified 401(k) Plan that provides for matching. The contributions under these plans were as follows (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Profit Sharing Plan | $ | 1,480 | $ | 1,279 | ||||
401(k) Plan | 477 | 677 | ||||||
Total contributions | $ | 1,957 | $ | 1,956 |
180
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 14 — Related Party Transactions
We have a 20% interest in EXXI M21K and account for this investment using the equity method. EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments within these quarterly consolidated financial statements.
We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for EP Energy Property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the three months ended September 30, 2014 and 2013, we have received $0.9 million and $0.6 million, respectively, related to such guarantees.
Prior to the LLOG Exploration acquisition, EGC received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties purchase on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three months ended September 30, 2014 and 2013, EGC received management fees of $0.9 million and $0.7 million, respectively.
On April 1, 2014, EXXI GOM closed on sale of its interest in Eugene Island 330 and South Marsh Island 128 properties to M21K and on June 3, 2014, it closed on the sale of its 100% interests in South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions within these quarterly consolidated financial statements.
Note 15 — Earnings per Share
Basic earnings per share of common stock is computed by dividing net income available for common stockholders by the weighted average number of shares of common stock outstanding during the year. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings per share (“EPS”) (in thousands, except per share data):
Three Months Ended September 30, | ||||||||
2014 (Restated) | 2013 (Restated) | |||||||
Net income | $ | 27,190 | $ | 25,282 | ||||
Preferred stock dividends | 2,872 | 2,873 | ||||||
Net income available for common stockholders | $ | 24,318 | $ | 22,409 | ||||
Weighted average shares outstanding for basic EPS | 93,833 | 75,782 | ||||||
Add dilutive securities | 8,467 | 8,291 | ||||||
Weighted average shares outstanding for diluted EPS | 102,300 | 84,073 | ||||||
Earnings per share | ||||||||
Basic | $ | 0.26 | $ | 0.30 | ||||
Diluted | $ | 0.24 | $ | 0.27 |
181
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 15 — Earnings per Share – (continued)
For the three months ended September 30, 2014 and 2013, no common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.
Note 16 — Commitments and Contingencies
Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.
Litigation Related to 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; 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.
182
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 16 — Commitments and Contingencies – (continued)
Lease Commitments. We have non-cancelable operating leases for office space and other that expire through December 31, 2022. Future minimum lease commitments as of September 30, 2014 under the operating leases are as follows (in thousands):
Year Ending September 30, | ||||
2015 | $ | 4,262 | ||
2016 | 5,107 | |||
2017 | 4,433 | |||
2018 | 4,190 | |||
2019 | 4,312 | |||
Thereafter | 12,880 | |||
Total | $ | 35,184 |
Rent expense, including rent incurred on short-term leases, for the three months ended September 30, 2014 and 2013 was approximately $1,159,000 and $937,000, respectively.
Letters of Credit and Performance Bonds. We had $226 million in letters of credit and $170.5 million of performance bonds outstanding as of September 30, 2014.
Guarantee. EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 5 — Equity Method Investments within these quarterly consolidated financial statements. We have provided guarantees related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 properties acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. See Note 14 — Related Party Transactions within these quarterly consolidated financial statements.
Drilling Rig Commitments. The drilling rig commitments represent minimum future expenditures for drilling rig services. The expenditures for drilling rig services will exceed such minimum amounts to the extent we utilize the drilling rigs subject to a particular contractual commitment for a period greater than the period set forth in the governing contract. As of September 30, 2014, we have the following drilling rig commitments:
1) | April 10, 2014 to October 27, 2014 at $54,448 per day; |
2) | September 1, 2013 to November 30, 2014 at $130,000 per day; |
3) | March 10, 2014 to March 9, 2015 at $53,175 per day; |
4) | February 15, 2014 to December 29, 2014 at $111,380 per day; |
5) | April 11, 2014 to October 12, 2014 at $112,000 per day; |
6) | July 1, 2014 to October 21, 2014 at $107,500 per day; and |
7) | October 4, 2014 to November 4, 2014 at $107,500 per day. |
At September 30, 2014, future minimum commitments under these contracts totaled $34.8 million.
183
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 17 — Fair Value of Financial Instruments
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:
The carrying amounts approximate fair value for cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable due to the short-term nature or maturity of the instruments.
Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 9 — Derivative Financial Instruments within these quarterly consolidated financial statements.
The fair values of our stock based units are based on period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model is used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on TSR Performance-Based Units valuation.
Valuation techniques are generally classified into three categories: the market approach, the income approach and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
• | Level 1 — quoted prices in active markets for identical assets or liabilities. |
• | Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). |
• | Level 3 — unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. |
184
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 17 — Fair Value of Financial Instruments – (continued)
During the quarter ended September 30, 2014, we did not have any transfers from or to Level 3. The following table presents the fair value of our Level 1 and Level 2 financial instruments (in thousands):
Level 1 | Level 2 | |||||||||||||||
As of September 30, 2014 | As of June 30, 2014 | As of September 30, 2014 | As of June 30, 2014 | |||||||||||||
Assets: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 40,248 | $ | 26,975 | ||||||||
Liabilities: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 11,166 | $ | 58,778 | ||||||||
Restricted stock units | 2,493 | 9,425 | — | — | ||||||||||||
Time-based performance units | 686 | 3,698 | — | — | ||||||||||||
Total liabilities | $ | 3,179 | $ | 13,123 | $ | 11,166 | $ | 58,778 |
The following table describes the changes to our Level 3 financial instruments (in thousands):
Three Months Ended September 30, | ||||||||
2014 | 2013 | |||||||
Liabilities: | ||||||||
Performance-based performance units | ||||||||
Balance at beginning of period | $ | 6,910 | $ | 6,778 | ||||
Vested | — | (7,188 | ) | |||||
Grants charged to general and administrative expense | (6,069 | ) | 11,046 | |||||
Balance at end of period | $ | 841 | $ | 10,636 |
Note 18 — Prepayments and Accrued Liabilities
Prepayments and accrued liabilities consist of the following (in thousands):
September 30, 2014 | June 30, 2014 | |||||||
Prepaid expenses and other current assets | ||||||||
Advances to joint interest partners | $ | 10,821 | $ | 10,336 | ||||
Insurance | 29,739 | 37,088 | ||||||
Inventory | 7,168 | 7,020 | ||||||
Royalty deposit | 11,832 | 12,262 | ||||||
Other | 5,071 | 5,824 | ||||||
Total prepaid expenses and other current assets | $ | 64,631 | $ | 72,530 | ||||
Accrued liabilities | ||||||||
Advances from joint interest partners | 2,831 | 2,667 | ||||||
Employee benefits and payroll | 18,193 | 43,480 | ||||||
Interest payable | 48,216 | 26,490 | ||||||
Accrued hedge payable | 1,761 | 7,874 | ||||||
Undistributed oil and gas proceeds | 31,345 | 34,473 | ||||||
Severance taxes payable | 2,021 | 8,014 | ||||||
Other | 11,142 | 10,528 | ||||||
Total accrued liabilities | $ | 115,509 | $ | 133,526 |
185
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 19 — Subsequent Events
In October 2014 and in November 2014, we monetized certain WTI put contracts and certain Brent swap contracts related to calendar year 2015 and realized $21.3 million and $7.5 million, respectively.
On November 4, 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 December 12, 2014 to shareholders of record on November 28, 2014.
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to the Alternative Investment Market of the London Stock Exchange (“AIM”), to be effective any time on or before March 13, 2015.
Note 20 — Restatement of Previously Issued Consolidated Financial Statements
Prior to the issuance of this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.
The effects of the restatement on our consolidated financial statements are summarized below:
• | Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and |
• | Resulting adjustments required to deferred income taxes and income tax expense (benefit). |
186
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
While these non-cash reclassifications impact revenues, net income (loss) in each period, net income (loss) attributable to common stockholders, and net income (loss) per common share, as well as total stockholders’ equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:
As of September 30, 2014 | As of June 30, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Total Current Assets | $ | 398,395 | $ | — | $ | 398,395 | $ | 457,759 | $ | — | $ | 457,759 | ||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | 6,637,292 | (95,213 | ) | 6,542,079 | 6,524,602 | (97,339 | ) | 6,427,263 | ||||||||||||||||
Other property and equipment | 23,400 | — | 23,400 | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | 6,660,692 | (95,213 | ) | 6,565,479 | 6,544,362 | (97,339 | ) | 6,447,023 | ||||||||||||||||
Total Other Assets | 437,496 | — | 437,496 | 436,715 | — | 436,715 | ||||||||||||||||||
Total Assets | $ | 7,496,583 | $ | (95,213 | ) | $ | 7,401,370 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 | ||||||||||
Total Current Liabilities | $ | 703,657 | $ | — | $ | 703,657 | $ | 699,895 | $ | — | $ | 699,895 | ||||||||||||
Deferred Income Taxes | 685,121 | (29,783 | ) | 655,338 | 701,038 | (34,069 | ) | 666,969 | ||||||||||||||||
Other Non-Current Liabilities | 4,290,765 | — | 4,290,765 | 4,240,073 | — | 4,240,073 | ||||||||||||||||||
Total Liabilities | 5,679,543 | (29,783 | ) | 5,649,760 | 5,641,006 | (34,069 | ) | 5,606,937 | ||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | 1 | — | 1 | 1 | — | 1 | ||||||||||||||||||
Common stock | 469 | — | 469 | 468 | — | 468 | ||||||||||||||||||
Additional paid-in capital | 1,841,457 | — | 1,841,457 | 1,837,462 | — | 1,837,462 | ||||||||||||||||||
Accumulated deficit | (40,165 | ) | (50,152 | ) | (90,317 | ) | (19,626 | ) | (83,745 | ) | (103,371 | ) | ||||||||||||
Accumulated other comprehensive loss, net of income taxes | 15,278 | (15,278 | ) | — | (20,475 | ) | 20,475 | — | ||||||||||||||||
Total Stockholders’ Equity | 1,817,040 | (65,430 | ) | 1,751,610 | 1,797,830 | (63,270 | ) | 1,734,560 | ||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 7,496,583 | $ | (95,213 | ) | $ | 7,401,370 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 |
187
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands, except share information) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | 368,501 | $ | 1,654 | $ | 370,155 | $ | 289,229 | $ | 1,737 | $ | 290,966 | ||||||||||||
Natural gas sales | 34,730 | (169 | ) | 34,561 | 35,363 | (2,779 | ) | 32,584 | ||||||||||||||||
Gain (loss) on derivative financial instruments | — | 56,725 | 56,725 | — | (30,403 | ) | (30,403 | ) | ||||||||||||||||
Total Revenues | 403,231 | 58,210 | 461,441 | 324,592 | (31,445 | ) | 293,147 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 161,266 | (2,126 | ) | 159,140 | 100,216 | (2,556 | ) | 97,660 | ||||||||||||||||
(Gain) loss on derivative financial instruments | (3,283 | ) | 3,283 | — | 1,441 | (1,441 | ) | — | ||||||||||||||||
All other costs and expenses | 194,109 | — | 194,109 | 123,504 | — | 123,504 | ||||||||||||||||||
Total Costs and Expenses | 352,092 | 1,157 | 353,249 | 225,161 | (3,997 | ) | 221,164 | |||||||||||||||||
Operating Income | 51,139 | 57,053 | 108,192 | 99,431 | (27,448 | ) | 71,983 | |||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Loss from equity method investees | 881 | 78 | 959 | (1,793 | ) | (314 | ) | (2,107 | ) | |||||||||||||||
Other income, net | 951 | — | 951 | 522 | — | 522 | ||||||||||||||||||
Interest expense | (66,263 | ) | — | (66,263 | ) | (29,685 | ) | — | (29,685 | ) | ||||||||||||||
Total Other Expense, net | (64,431 | ) | 78 | (64,353 | ) | (30,956 | ) | (314 | ) | (31,270 | ) | |||||||||||||
Income (Loss) Before Income Taxes | (13,292 | ) | 57,131 | 43,839 | 68,475 | (27,762 | ) | 40,713 | ||||||||||||||||
Income Tax Expense (Benefit) | (6,889 | ) | 23,538 | 16,649 | 25,336 | (9,905 | ) | 15,431 | ||||||||||||||||
Net Income (Loss) | (6,403 | ) | 33,593 | 27,190 | 43,139 | (17,857 | ) | 25,282 | ||||||||||||||||
Preferred Stock Dividends | 2,872 | — | 2,872 | 2,873 | — | 2,873 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (9,275 | ) | $ | 33,593 | $ | 24,318 | $ | 40,266 | $ | (17,857 | ) | $ | 22,409 | ||||||||||
Earnings (Loss) per Share | ||||||||||||||||||||||||
Basic | $ | (0.10 | ) | $ | 0.26 | $ | 0.53 | $ | 0.30 | |||||||||||||||
Diluted | $ | (0.10 | ) | $ | 0.24 | $ | 0.51 | $ | 0.27 | |||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||||||
Basic | 93,833 | 93,833 | 75,782 | 75,782 | ||||||||||||||||||||
Diluted | 93,833 | 102,300 | 84,073 | 84,073 | ||||||||||||||||||||
Net Income (Loss) | $ | (6,403 | ) | $ | 33,593 | $ | 27,190 | $ | 43,139 | $ | (17,857 | ) | $ | 25,282 | ||||||||||
Other Comprehensive Loss | ||||||||||||||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||||||||||||||
Unrealized change in fair value net of ineffective portion | 56,993 | (56,993 | ) | — | (22,971 | ) | 22,971 | — | ||||||||||||||||
Effective portion reclassified to earnings during the period | (1,988 | ) | 1,988 | — | (7,348 | ) | 7,348 | — | ||||||||||||||||
Total Other Comprehensive Loss | 55,005 | (55,005 | ) | — | (30,319 | ) | 30,319 | — | ||||||||||||||||
Income Tax Expense (Benefit) | 19,252 | (19,252 | ) | — | (10,611 | ) | 10,611 | |||||||||||||||||
Net Other Comprehensive Income (Loss) | 35,753 | (35,753 | ) | — | (19,708 | ) | 19,708 | — | ||||||||||||||||
Comprehensive Income | $ | 29,350 | $ | (2,160 | ) | $ | 27,190 | $ | 23,431 | $ | 1,851 | $ | 25,282 |
188
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Three Months Ended September 30, 2014 | Three Months Ended September 30, 2013 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (6,403 | ) | $ | 33,593 | $ | 27,190 | $ | 43,139 | $ | (17,857 | ) | $ | 25,282 | ||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 161,266 | (2,126 | ) | 159,140 | 100,216 | (2,556 | ) | 97,660 | ||||||||||||||||
Deferred income tax expense (benefit) | (7,169 | ) | 23,538 | 16,369 | 22,480 | (9,906 | ) | 12,574 | ||||||||||||||||
Change in fair value of derivative financial instruments | (2,574 | ) | (52,521 | ) | (55,095 | ) | (2,357 | ) | 29,862 | 27,505 | ||||||||||||||
Accretion of asset retirement obligations | 12,819 | — | 12,819 | 7,326 | — | 7,326 | ||||||||||||||||||
Loss (income) from equity method investees | (881 | ) | (78 | ) | (959 | ) | 1,793 | 314 | 2,107 | |||||||||||||||
Amortization and write-off of debt issuance costs and other | 5,277 | (2,533 | ) | 2,744 | 1,455 | — | 1,455 | |||||||||||||||||
Stock-based compensation | 1,779 | — | 1,779 | 3,532 | — | 3,532 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | 23,313 | — | 23,313 | (2,131 | ) | — | (2,131 | ) | ||||||||||||||||
Prepaid expenses and other current assets | 7,661 | — | 7,661 | (6,270 | ) | — | (6,270 | ) | ||||||||||||||||
Settlement of asset retirement obligations | (14,907 | ) | — | (14,907 | ) | (18,063 | ) | — | (18,063 | ) | ||||||||||||||
Accounts payable and accrued liabilities | 23,769 | 127 | 23,896 | (43,221 | ) | 143 | (43,078 | ) | ||||||||||||||||
Net Cash Provided by Operating Activities | 203,950 | — | 203,950 | 107,899 | — | 107,899 | ||||||||||||||||||
Net Cash Used in Investing Activities | (272,148 | ) | — | (272,148 | ) | (213,370 | ) | — | (213,370 | ) | ||||||||||||||
Net Cash Provided by Financing Activities | 41,892 | — | 41,892 | 122,833 | — | 122,833 | ||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (26,306 | ) | — | (26,306 | ) | 17,362 | — | 17,362 | ||||||||||||||||
Cash and Cash Equivalents, beginning of period | 145,806 | 145,806 | — | — | ||||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 119,500 | $ | 119,500 | $ | 17,362 | $ | 17,362 |
189
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information
Our indirect, 100%-owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the above senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s revolving credit facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC requires the issuer and guarantors to file separate financial statements. The Company meets the conditions in Rule 3-10 to report information about the assets, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to the parent company’s financial statements condensed consolidating financial information for the same periods as those presented for the parent company financial statements.
The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, the guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses. The following supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements and should be read in conjunction with our consolidated financial statements and notes thereto included in the this Form 10-K.
190
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
September 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 121,359 | $ | — | $ | — | $ | 723 | $ | (2,582 | ) | $ | 119,500 | |||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 107,416 | 44,373 | (5,968 | ) | 145,821 | |||||||||||||||||
Joint interest billings | — | 2,064 | — | 12,362 | — | 14,426 | ||||||||||||||||||
Other | 505 | 2,482 | 333 | 2,295 | — | 5,615 | ||||||||||||||||||
Prepaid expenses and other current assets | 58 | 30,682 | 491 | 33,400 | — | 64,631 | ||||||||||||||||||
Deferred income taxes | — | — | — | 24,587 | — | 24,587 | ||||||||||||||||||
Derivative financial instruments | — | 21,553 | — | 2,262 | — | 23,815 | ||||||||||||||||||
Total Current Assets | 121,922 | 56,781 | 108,240 | 120,002 | (8,550 | ) | 398,395 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,257,654 | 3,278,212 | 6,213 | 6,542,079 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 23,400 | — | 23,400 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,257,654 | 3,301,612 | 6,213 | 6,565,479 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Goodwill | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Derivative financial instruments | — | 6,550 | — | 163 | — | 6,713 | ||||||||||||||||||
Equity investments | 1,712,476 | 2,868,268 | — | 2,109,607 | (6,650,031 | ) | 40,320 | |||||||||||||||||
Intercompany receivables | 110,116 | 1,740,275 | — | — | (1,850,391 | ) | — | |||||||||||||||||
Restricted cash | — | — | 325 | — | — | 325 | ||||||||||||||||||
Other assets and debt issuance costs, net | 177,946 | 42,265 | — | 11,634 | (171,000 | ) | 60,845 | |||||||||||||||||
Total Other Assets | 2,000,538 | 4,657,358 | 325 | 2,450,697 | (8,671,422 | ) | 437,496 | |||||||||||||||||
Total Assets | $ | 2,122,460 | $ | 4,714,139 | $ | 3,366,219 | $ | 5,872,311 | $ | (8,673,759 | ) | $ | 7,401,370 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 93,451 | $ | 144,590 | $ | 242,808 | $ | (8,741 | ) | $ | 472,108 | |||||||||||
Accrued liabilities | 4,664 | 42,061 | 25,494 | 111,441 | (68,151 | ) | 115,509 | |||||||||||||||||
Notes payable | — | 19,368 | — | — | — | 19,368 | ||||||||||||||||||
Deferred income taxes | — | — | — | — | — | — | ||||||||||||||||||
Asset retirement obligations | — | — | 39,783 | 39,831 | — | 79,614 | ||||||||||||||||||
Derivative financial instruments | — | — | — | 1,446 | — | 1,446 | ||||||||||||||||||
Current maturities of long-term debt | — | 14,591 | — | 1,021 | — | 15,612 | ||||||||||||||||||
Total Current Liabilities | 4,664 | 169,471 | 209,867 | 396,547 | (76,892 | ) | 703,657 | |||||||||||||||||
Long-term debt, less current maturities | 345,741 | 2,361,717 | — | 1,263,959 | (171,000 | ) | 3,800,417 | |||||||||||||||||
Deferred income taxes | 20,445 | 158,707 | — | 476,186 | — | 655,338 | ||||||||||||||||||
Asset retirement obligations | — | 50 | 249,871 | 232,418 | — | 482,339 | ||||||||||||||||||
Intercompany payables | — | — | 1,674,648 | 21,197 | (1,695,845 | ) | — | |||||||||||||||||
Other liabilities | — | — | — | 8,009 | — | 8,009 | ||||||||||||||||||
Total Liabilities | 370,850 | 2,689,945 | 2,134,386 | 2,398,316 | (1,943,737 | ) | 5,649,760 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 469 | 1 | — | 11 | (12 | ) | 469 | |||||||||||||||||
Additional paid-in capital | 1,841,457 | 2,054,645 | 339,400 | 3,367,862 | (5,761,907 | ) | 1,841,457 | |||||||||||||||||
Accumulated earnings (deficit) | (90,317 | ) | (30,452 | ) | 892,433 | 106,122 | (968,103 | ) | (90,317 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,751,610 | 2,024,194 | 1,231,833 | 3,473,995 | (6,730,022 | ) | 1,751,610 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 2,122,460 | $ | 4,714,139 | $ | 3,366,219 | $ | 5,872,311 | $ | (8,673,759 | ) | $ | 7,401,370 |
191
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
June 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 135,703 | $ | 3,723 | $ | — | $ | 6,380 | $ | — | $ | 145,806 | ||||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 127,773 | 50,990 | (11,688 | ) | 167,075 | |||||||||||||||||
Joint interest billings | — | 1,833 | — | 11,065 | — | 12,898 | ||||||||||||||||||
Other | 10 | 3,452 | 517 | 1,460 | (1 | ) | 5,438 | |||||||||||||||||
Prepaid expenses and other current assets | 230 | 27,705 | 350 | 44,245 | — | 72,530 | ||||||||||||||||||
Deferred income taxes | — | 27,424 | — | 25,163 | — | 52,587 | ||||||||||||||||||
Derivative financial instruments | — | 1,425 | — | — | — | 1,425 | ||||||||||||||||||
Total Current Assets | 135,943 | 65,562 | 128,640 | 139,303 | (11,689 | ) | 457,759 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,227,584 | 3,197,765 | 1,914 | 6,427,263 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,227,584 | 3,217,525 | 1,914 | 6,447,023 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Goodwill | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Derivative financial instruments | — | 3,035 | — | — | — | 3,035 | ||||||||||||||||||
Equity investments | 1,681,640 | 2,871,756 | — | 2,291,045 | (6,803,798 | ) | 40,643 | |||||||||||||||||
Intercompany receivables | 102,489 | 1,627,931 | — | 80,983 | (1,811,403 | ) | — | |||||||||||||||||
Restricted cash | — | — | 325 | 6,025 | — | 6,350 | ||||||||||||||||||
Other assets and debt issuance costs, net | 178,299 | 42,155 | — | 7,940 | (171,000 | ) | 57,394 | |||||||||||||||||
Total Other Assets | 1,962,428 | 4,544,877 | 325 | 2,715,286 | (8,786,201 | ) | 436,715 | |||||||||||||||||
Total Assets | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 64,533 | $ | 150,909 | $ | 214,215 | $ | (11,881 | ) | $ | 417,776 | |||||||||||
Accrued liabilities | 1,640 | 12,501 | 28,750 | 154,587 | (63,952 | ) | 133,526 | |||||||||||||||||
Notes payable | — | 21,967 | — | — | — | 21,967 | ||||||||||||||||||
Deferred income taxes | 19,185 | — | — | — | (19,185 | ) | — | |||||||||||||||||
Asset retirement obligations | — | — | 39,819 | 39,830 | — | 79,649 | ||||||||||||||||||
Derivative financial instruments | — | 5,517 | — | 26,440 | — | 31,957 | ||||||||||||||||||
Current maturities of long-term debt | — | 14,093 | — | 927 | — | 15,020 | ||||||||||||||||||
Total Current Liabilities | 20,825 | 118,611 | 219,478 | 435,999 | (95,018 | ) | 699,895 | |||||||||||||||||
Long-term debt, less current maturities | 342,986 | 2,305,906 | — | 1,266,732 | (171,000 | ) | 3,744,624 | |||||||||||||||||
Deferred income taxes | — | 177,007 | — | 470,755 | 19,207 | 666,969 | ||||||||||||||||||
Asset retirement obligations | — | 49 | 247,272 | 232,864 | — | 480,185 | ||||||||||||||||||
Derivative financial instruments | — | 2,166 | — | 2,140 | — | 4,306 | ||||||||||||||||||
Intercompany payables | — | — | 1,640,094 | — | (1,640,094 | ) | — | |||||||||||||||||
Other liabilities | — | — | — | 10,958 | — | 10,958 | ||||||||||||||||||
Total Liabilities | 363,811 | 2,603,739 | 2,106,844 | 2,419,448 | (1,866,905 | ) | 5,606,937 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 468 | 1 | 10 | (11 | ) | 468 | ||||||||||||||||||
Additional paid-in capital | 1,837,462 | 2,092,439 | 273,129 | 3,580,005 | (5,945,573 | ) | 1,837,462 | |||||||||||||||||
Accumulated earnings (deficit) | (103,371 | ) | (85,740 | ) | 976,576 | 72,651 | (963,487 | ) | (103,371 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,734,560 | 2,006,700 | 1,249,705 | 3,652,666 | (6,909,071 | ) | 1,734,560 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 |
192
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended September 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 211,840 | $ | 158,315 | $ | — | $ | 370,155 | ||||||||||||
Natural gas sales | — | — | 20,607 | 13,954 | — | 34,561 | ||||||||||||||||||
Gain on derivative financial instruments | — | 34,868 | — | 21,857 | 56,725 | |||||||||||||||||||
Total Revenues | — | 34,868 | 232,447 | 194,126 | — | 461,441 | ||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (86 | ) | 85,746 | 56,925 | — | 142,585 | |||||||||||||||||
Production taxes | — | 14 | 1,121 | 1,958 | — | 3,093 | ||||||||||||||||||
Gathering and transportation | — | — | 9,188 | — | — | 9,188 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 91,064 | 74,483 | (6,407 | ) | 159,140 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 6,638 | 6,181 | — | 12,819 | ||||||||||||||||||
General and administrative expense | 1,147 | 1,771 | 4,610 | 18,896 | — | 26,424 | ||||||||||||||||||
Total Costs and Expenses | 1,147 | 1,699 | 198,367 | 158,443 | (6,407 | ) | 353,249 | |||||||||||||||||
Operating Income (Loss) | (1,147 | ) | 33,169 | 34,080 | 35,683 | 6,407 | 108,192 | |||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 30,839 | 61,901 | — | 3,043 | (94,824 | ) | 959 | |||||||||||||||||
Other income (expense) – net | 5,172 | 484 | — | 5,349 | (10,054 | ) | 951 | |||||||||||||||||
Interest expense | (6,133 | ) | (47,653 | ) | (1,495 | ) | (10,982 | ) | — | (66,263 | ) | |||||||||||||
Total Other Expense | 29,878 | 14,732 | (1,495 | ) | (2,590 | ) | (104,878 | ) | (64,353 | ) | ||||||||||||||
Income (Loss) Before Income Taxes | 28,731 | 47,901 | 32,585 | 33,093 | (98,471 | ) | 43,839 | |||||||||||||||||
Income Tax Expense (Benefit) | 1,541 | 12,301 | — | 2,807 | — | 16,649 | ||||||||||||||||||
Net Income | 27,190 | 35,600 | 32,585 | 30,286 | (98,471 | ) | 27,190 | |||||||||||||||||
Preferred Stock Dividends | 2,872 | — | — | — | — | 2,872 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | 24,318 | $ | 35,600 | $ | 32,585 | $ | 30,286 | $ | (98,471 | ) | $ | 24,318 |
193
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 290,966 | $ | — | $ | — | $ | 290,966 | ||||||||||||
Natural gas sales | — | — | 32,584 | — | — | 32,584 | ||||||||||||||||||
Loss on derivative financial instruments | — | (30,403 | ) | — | — | — | (30,403 | ) | ||||||||||||||||
Total Revenues | — | (30,403 | ) | 323,550 | — | — | 293,147 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (243 | ) | 86,006 | — | — | 85,763 | |||||||||||||||||
Production taxes | — | 15 | 1,383 | — | — | 1,398 | ||||||||||||||||||
Gathering and transportation | — | — | 5,345 | — | — | 5,345 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 96,905 | 755 | — | 97,660 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 7,326 | — | — | 7,326 | ||||||||||||||||||
General and administrative expense | 1,624 | (205 | ) | 21,534 | 719 | — | 23,672 | |||||||||||||||||
Total Costs and Expenses | 1,624 | (433 | ) | 218,499 | 1,474 | — | 221,164 | |||||||||||||||||
Operating Income (Loss) | (1,624 | ) | (29,970 | ) | 105,051 | (1,474 | ) | — | 71,983 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 23,601 | 111,204 | — | 45,607 | (182,519 | ) | (2,107 | ) | ||||||||||||||||
Other income (expense) – net | 4,723 | 483 | — | 4,488 | (9,172 | ) | 522 | |||||||||||||||||
Interest expense | (1 | ) | (28,088 | ) | (1,516 | ) | (80 | ) | — | (29,685 | ) | |||||||||||||
Total Other Income (Expense) | 28,323 | 83,599 | (1,516 | ) | 50,015 | (191,691 | ) | (31,270 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 26,699 | 53,629 | 103,535 | 48,541 | (191,691 | ) | 40,713 | |||||||||||||||||
Income Tax Expense (Benefit) | 1,417 | 23,459 | — | (9,445 | ) | — | 15,431 | |||||||||||||||||
Net Income | 25,282 | 30,170 | 103,535 | 57,986 | (191,691 | ) | 25,282 | |||||||||||||||||
Preferred Stock Dividends | 2,873 | — | — | — | — | 2,873 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | 22,409 | $ | 30,170 | $ | 103,535 | $ | 57,986 | $ | (191,691 | ) | $ | 22,409 |
194
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Three Months Ended September 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 27,190 | $ | 35,600 | $ | 32,585 | $ | 30,286 | $ | (98,471 | ) | $ | 27,190 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 91,064 | 74,483 | (6,407 | ) | 159,140 | |||||||||||||||||
Deferred income tax expense | 1,260 | 12,301 | — | 2,808 | — | 16,369 | ||||||||||||||||||
Change in fair value of derivative financial instruments | — | (35,047 | ) | — | (20,048 | ) | — | (55,095 | ) | |||||||||||||||
Accretion of asset retirement obligations | — | — | 6,638 | 6,181 | — | 12,819 | ||||||||||||||||||
Loss from equity method investees | (30,839 | ) | (61,901 | ) | — | (3,043 | ) | 94,824 | (959 | ) | ||||||||||||||
Amortization and write-off of debt issuance costs and other | 3,108 | (364 | ) | — | — | — | 2,744 | |||||||||||||||||
Stock-based compensation | 1,779 | — | — | — | — | 1,779 | ||||||||||||||||||
Changes in operating assets and liabilities | — | |||||||||||||||||||||||
Accounts receivable | (496 | ) | 4,463 | 20,541 | 4,525 | (5,720 | ) | 23,313 | ||||||||||||||||
Prepaid expenses and other current assets | 174 | (2,977 | ) | (141 | ) | 10,606 | (1 | ) | 7,661 | |||||||||||||||
Settlement of asset retirement obligations | — | — | (7,717 | ) | (7,190 | ) | — | (14,907 | ) | |||||||||||||||
Accounts payable and accrued liabilities | (4,601 | ) | (9,712 | ) | (25,479 | ) | (102,503 | ) | 166,191 | 23,896 | ||||||||||||||
Net Cash Provided by (Used in) Operating Activities | (2,425 | ) | (57,637 | ) | 117,491 | (3,895 | ) | 150,416 | 203,950 | |||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (287 | ) | — | — | (287 | ) | ||||||||||||||||
Capital expenditures | — | — | (124,151 | ) | (155,859 | ) | — | (280,010 | ) | |||||||||||||||
Change in equity method investments | — | — | — | 154,282 | (153,000 | ) | 1,282 | |||||||||||||||||
Proceeds from the sale of properties | — | — | 6,947 | — | — | 6,947 | ||||||||||||||||||
Other | — | — | — | (80 | ) | — | (80 | ) | ||||||||||||||||
Net Cash (Used in) Investing Activities | — | — | (117,491 | ) | (1,657 | ) | (153,000 | ) | (272,148 | ) | ||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,217 | — | — | — | — | 2,217 | ||||||||||||||||||
Dividends to shareholders – common | (11,264 | ) | — | — | — | — | (11,264 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (2,872 | ) | — | — | — | — | (2,872 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 510,120 | — | — | — | 510,120 | ||||||||||||||||||
Payments on long-term debt | — | (453,937 | ) | — | (105 | ) | — | (454,042 | ) | |||||||||||||||
Debt issuance costs | — | (2,250 | ) | — | — | — | (2,250 | ) | ||||||||||||||||
Other | — | (19 | ) | — | — | 2 | (17 | ) | ||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (11,919 | ) | 53,914 | — | (105 | ) | 2 | 41,892 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | (14,344 | ) | (3,723 | ) | — | (5,657 | ) | (2,582 | ) | (26,306 | ) | |||||||||||||
Cash and Cash Equivalents, beginning of period | 135,703 | 3,723 | — | 6,380 | — | 145,806 | ||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 121,359 | $ | — | $ | — | $ | 723 | $ | (2,582 | ) | $ | 119,500 |
195
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 25,282 | $ | 30,170 | $ | 103,535 | $ | 57,986 | $ | (191,691 | ) | $ | 25,282 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 96,905 | 755 | — | 97,660 | ||||||||||||||||||
Deferred income tax expense | (1,439 | ) | 23,458 | — | (9,445 | ) | — | 12,574 | ||||||||||||||||
Change in fair value of derivative financial instruments | — | 27,505 | — | — | — | 27,505 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 7,326 | — | — | 7,326 | ||||||||||||||||||
Loss from equity method investees | (23,601 | ) | (111,204 | ) | — | (45,607 | ) | 182,519 | 2,107 | |||||||||||||||
Amortization and write-off of debt issuance costs and other | — | 1,445 | — | 10 | — | 1,455 | ||||||||||||||||||
Stock-based compensation | 3,532 | — | — | — | — | 3,532 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | — | 5,699 | (2,356 | ) | (1,049 | ) | (4,425 | ) | (2,131 | ) | ||||||||||||||
Prepaid expenses and other current assets | 158 | (4,070 | ) | (41 | ) | (2,318 | ) | 1 | (6,270 | ) | ||||||||||||||
Settlement of asset retirement obligations | — | — | (18,063 | ) | — | — | (18,063 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | 5,850 | (151,911 | ) | 20,389 | 75,884 | 6,710 | (43,078 | ) | ||||||||||||||||
Net Cash Provided by (Used in) Operating Activities | 9,782 | (178,908 | ) | 207,695 | 76,216 | (6,886 | ) | 107,899 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (15 | ) | — | — | (15 | ) | ||||||||||||||||
Capital expenditures | — | 12,059 | (209,428 | ) | (989 | ) | — | (198,358 | ) | |||||||||||||||
Change in equity method investments | — | — | — | (16,694 | ) | — | (16,694 | ) | ||||||||||||||||
Intercompany investment | (1,000 | ) | — | — | — | 1,000 | — | |||||||||||||||||
Proceeds from the sale of properties | — | — | 1,748 | — | — | 1,748 | ||||||||||||||||||
Other | — | — | — | (51 | ) | — | (51 | ) | ||||||||||||||||
Net Cash Used in (Provided by) Investing Activities | (1,000 | ) | 12,059 | (207,695 | ) | (17,734 | ) | 1,000 | (213,370 | ) | ||||||||||||||
Cash Flows from Financing Activities | �� | |||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 3,267 | — | — | — | — | 3,267 | ||||||||||||||||||
Repurchase of company common stock | — | — | — | (35,210 | ) | — | (35,210 | ) | ||||||||||||||||
Dividends to shareholders – common | (9,096 | ) | — | — | — | — | (9,096 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (2,873 | ) | — | — | — | — | (2,873 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 1,040,697 | — | — | — | 1,040,697 | ||||||||||||||||||
Payments on long-term debt | — | (865,128 | ) | — | (103 | ) | — | (865,231 | ) | |||||||||||||||
Debt issuance costs | — | (8,720 | ) | — | — | — | (8,720 | ) | ||||||||||||||||
Other | — | — | — | (1 | ) | — | (1 | ) | ||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (8,702 | ) | 166,849 | — | (35,314 | ) | — | 122,833 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | 80 | — | — | 23,168 | (5,886 | ) | 17,362 | |||||||||||||||||
Cash and Cash Equivalents, beginning of period | 1,334 | — | — | 137 | (1,471 | ) | — | |||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 1,414 | $ | — | $ | — | $ | 23,305 | $ | (7,357 | ) | $ | 17,362 |
196
Restated Quarterly Financial Statements for the Three and Six Months Ended December 31, 2014
ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS
(In thousands, except share information)
(Unaudited)
December 31, 2014 (Restated) | June 30, 2014 (Restated) | |||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 101,284 | $ | 145,806 | ||||
Accounts receivable | ||||||||
Oil and natural gas sales | 102,882 | 167,075 | ||||||
Joint interest billings | 19,098 | 12,898 | ||||||
Other | 30,728 | 5,438 | ||||||
Prepaid expenses and other current assets | 50,178 | 72,530 | ||||||
Deferred income taxes | 11,235 | 52,587 | ||||||
Derivative financial instruments | 150,026 | 1,425 | ||||||
Total Current Assets | 465,431 | 457,759 | ||||||
Property and Equipment | ||||||||
Oil and natural gas properties, net – full cost method of accounting, including $807.8 million and $1,165.7 million of unevaluated properties not being amortized at December 31, 2014 and June 30, 2014, respectively | 6,549,530 | 6,427,263 | ||||||
Other property and equipment, net | 23,833 | 19,760 | ||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 6,573,363 | 6,447,023 | ||||||
Other Assets | ||||||||
Goodwill | — | 329,293 | ||||||
Derivative financial instruments | 8,377 | 3,035 | ||||||
Equity investments | 27,685 | 40,643 | ||||||
Restricted Cash | 6,024 | 6,350 | ||||||
Other assets and debt issuance costs, net of accumulated amortization | 50,128 | 57,394 | ||||||
Total Other Assets | 92,214 | 436,715 | ||||||
Total Assets | $ | 7,131,008 | $ | 7,341,497 | ||||
LIABILITIES | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 312,568 | $ | 417,776 | ||||
Accrued liabilities | 91,665 | 133,526 | ||||||
Notes payable | 12,175 | 21,967 | ||||||
Asset retirement obligations | 79,573 | 79,649 | ||||||
Derivative financial instruments | — | 31,957 | ||||||
Current maturities of long-term debt | 21,702 | 15,020 | ||||||
Total Current Liabilities | 517,683 | 699,895 | ||||||
Long-term debt, less current maturities | 3,989,922 | 3,744,624 | ||||||
Deferred income taxes | 682,063 | 666,969 | ||||||
Asset retirement obligations | 470,523 | 480,185 | ||||||
Derivative financial instruments | — | 4,306 | ||||||
Other liabilities | 8,629 | 10,958 | ||||||
Total Liabilities | 5,668,820 | 5,606,937 |
See accompanying Notes to Consolidated Financial Statements
197
ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS – (continued)
(In thousands, except share information)
(Unaudited)
December 31, 2014 (Restated) | June 30, 2014 (Restated) | |||||||
Commitments and Contingencies (Note 17) | ||||||||
Stockholders’ Equity | ||||||||
Preferred stock, $0.001 par value, 7,500,000 shares authorized at December 31, 2014 and June 30, 2014 | ||||||||
7.25% Convertible perpetual preferred stock, 3,000 and 8,000 shares issued and outstanding at December 31, 2014 and June 30, 2014, respectively | $ | — | $ | — | ||||
5.625% Convertible perpetual preferred stock, 812,759 and 812,760 shares issued and outstanding at December 31, 2014 and June 30, 2014, respectively | 1 | 1 | ||||||
Common stock, $0.005 par value, 200,000,000 shares authorized and 94,395,593 and 93,719,570 shares issued and outstanding at December 31, 2014 and June 30, 2014, respectively | 471 | 468 | ||||||
Additional paid-in capital | 1,842,152 | 1,837,462 | ||||||
Accumulated deficit | (380,436 | ) | (103,371 | ) | ||||
Total Stockholders’ Equity | 1,462,188 | 1,734,560 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 7,131,008 | $ | 7,341,497 |
See accompanying Notes to Consolidated Financial Statements
198
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share information)
(Unaudited)
Three Months Ended December 31, | Six Months Ended December 31, | |||||||||||||||
2014 (Restated) | 2013 (Restated) | 2014 (Restated) | 2013 (Restated) | |||||||||||||
Revenues | ||||||||||||||||
Crude oil sales | $ | 279,708 | $ | 263,627 | $ | 649,863 | $ | 554,593 | ||||||||
Natural gas sales | 31,801 | 31,138 | 66,362 | 63,722 | ||||||||||||
Gain (loss) on derivative financial instruments | 191,462 | (20,951 | ) | 248,187 | (51,354 | ) | ||||||||||
Total Revenues | 502,971 | 273,814 | 964,412 | 566,961 | ||||||||||||
Costs and Expenses | ||||||||||||||||
Lease operating | 119,366 | 93,789 | 261,951 | 179,552 | ||||||||||||
Production taxes | 2,263 | 1,189 | 5,356 | 2,587 | ||||||||||||
Gathering and transportation | 4,771 | 5,978 | 13,959 | 11,323 | ||||||||||||
Depreciation, depletion and amortization | 175,155 | 101,156 | 334,295 | 198,816 | ||||||||||||
Accretion of asset retirement obligations | 12,798 | 7,425 | 25,617 | 14,751 | ||||||||||||
Goodwill impairment | 329,293 | — | 329,293 | — | ||||||||||||
General and administrative expense | 27,745 | 17,698 | 54,169 | 41,370 | ||||||||||||
Total Costs and Expenses | 671,391 | 227,235 | 1,024,640 | 448,399 | ||||||||||||
Operating Income (Loss) | (168,420 | ) | 46,579 | (60,228 | ) | 118,562 | ||||||||||
Other Income (Expense) | ||||||||||||||||
Income (loss) from equity method investees | (1,275 | ) | (2,726 | ) | (316 | ) | (4,833 | ) | ||||||||
Other income – net | 991 | 913 | 1,942 | 1,435 | ||||||||||||
Interest expense | (66,901 | ) | (38,641 | ) | (133,164 | ) | (68,326 | ) | ||||||||
Total Other Expense | (67,185 | ) | (40,454 | ) | (131,538 | ) | (71,724 | ) | ||||||||
Income (Loss) Before Income Taxes | (235,605 | ) | 6,125 | (191,766 | ) | 46,838 | ||||||||||
Income Tax Expense (Benefit) | 40,358 | 4,197 | 57,007 | 19,628 | ||||||||||||
Net Income (Loss) | (275,963 | ) | 1,928 | (248,773 | ) | 27,210 | ||||||||||
Preferred Stock Dividends | 2,870 | 2,872 | 5,742 | 5,745 | ||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (278,833 | ) | $ | (944 | ) | $ | (254,515 | ) | $ | 21,465 | |||||
Earnings (Loss) per Share | ||||||||||||||||
Basic | $ | (2.97 | ) | $ | (0.01 | ) | $ | (2.71 | ) | $ | 0.29 | |||||
Diluted | $ | (2.97 | ) | $ | (0.01 | ) | $ | (2.71 | ) | $ | 0.29 | |||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||
Basic | 93,993 | 73,964 | 93,913 | 74,873 | ||||||||||||
Diluted | 93,993 | 73,964 | 93,913 | 74,956 |
See accompanying Notes to Consolidated Financial Statements
199
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Six Months Ended December 31, | ||||||||
2014 (Restated) | 2013 (Restated) | |||||||
Cash Flows From Operating Activities | ||||||||
Net income (loss) | $ | (248,773 | ) | $ | 27,210 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 334,295 | 198,816 | ||||||
Goodwill impairment | 329,293 | — | ||||||
Deferred income tax expense (benefit) | 56,447 | 16,505 | ||||||
Change in fair value of derivative financial instruments | (175,731 | ) | 46,655 | |||||
Accretion of asset retirement obligations | 25,617 | 14,751 | ||||||
Loss (income) from equity method investees | 316 | 4,833 | ||||||
Amortization and write-off of debt issuance costs and other | 5,615 | 4,555 | ||||||
Stock-based compensation | 2,632 | 3,971 | ||||||
Changes in operating assets and liabilities | ||||||||
Accounts receivable | 33,819 | 16,999 | ||||||
Prepaid expenses and other current assets | 22,483 | 6,219 | ||||||
Settlement of asset retirement obligations | (53,960 | ) | (34,038 | ) | ||||
Accounts payable and accrued liabilities | (170,745 | ) | (44,776 | ) | ||||
Net Cash Provided by Operating Activities | 161,308 | 261,700 | ||||||
Cash Flows from Investing Activities | ||||||||
Acquisitions | (287 | ) | (12,564 | ) | ||||
Capital expenditures | (449,114 | ) | (388,227 | ) | ||||
Change in equity method investments | 12,642 | (11,694 | ) | |||||
Transfers from (to) restricted cash | 325 | (746 | ) | |||||
Proceeds from the sale of properties | 6,947 | 1,748 | ||||||
Other | 95 | (72 | ) | |||||
Net Cash Used in Investing Activities | (429,392 | ) | (411,555 | ) | ||||
Cash Flows from Financing Activities | ||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,059 | 3,405 | ||||||
Proceeds from convertible debt allocated to additional paid-in capital | — | 63,432 | ||||||
Repurchase of company common stock | — | (153,491 | ) | |||||
Dividends to shareholders – common | (22,548 | ) | (17,798 | ) | ||||
Dividends to shareholders – preferred | (5,744 | ) | (5,745 | ) | ||||
Proceeds from long-term debt | 1,011,948 | 1,764,685 | ||||||
Payments on long-term debt | (759,851 | ) | (1,127,879 | ) | ||||
Debt issuance costs | (2,302 | ) | (18,923 | ) | ||||
Other | — | (3 | ) | |||||
Net Cash Provided by Financing Activities | 223,562 | 507,683 | ||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (44,522 | ) | 357,828 | |||||
Cash and Cash Equivalents, beginning of period | 145,806 | — | ||||||
Cash and Cash Equivalents, end of period | $ | 101,284 | $ | 357,828 |
See accompanying Notes to Consolidated Financial Statements
200
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 1 — Organization and Summary of Significant Accounting Policies
Nature of Operations. Energy XXI Ltd (“Energy XXI”) was incorporated in Bermuda on July 25, 2005. References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. With our principal operating subsidiary 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 in the Gulf of Mexico Shelf (“GoM Shelf”).
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to the Alternative Investment Market of the London Stock Exchange (“AIM”). We successfully delisted from AIM on December 15, 2014 but continue to be listed on the NASDAQ Global Select Market (“NASDAQ”).
Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.
Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in this Form 10-K.
Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
201
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 2 — Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual periods beginning after December 15, 2016, and interim periods within those annual reporting periods. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our consolidated financial position, results of operations or cash flows.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15,Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
Note 3 — Acquisitions and Dispositions
Black Elk Interest
On December 20, 2013, we acquired certain offshore Louisiana interests in the West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013, and we are the operator of these properties.
Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):
Oil and natural gas properties – evaluated | $ | 15,821 | ||
Oil and natural gas properties – unevaluated | 6,586 | |||
Asset retirement obligations | (10,503 | ) | ||
Net working capital* | (1,500 | ) | ||
Cash paid | $ | 10,404 |
* | Net working capital includes payables. |
Walter Oil & Gas Corporation Oil and Gas Properties Interests
On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million. This acquisition was effective as of January 1, 2014 and we are the operator of these properties.
Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):
Oil and natural gas properties – evaluated | $ | 23,497 | ||
Asset retirement obligations | (705 | ) | ||
Cash paid | $ | 22,792 |
202
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; and (3) a credit adjusted risk-free interest rate. Fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 18 — Fair Value of Financial Instruments.
EPL Oil & Gas, Inc. (“EPL”)
We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.
In the EPL acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election”) and collectively the (“Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of our common stock and paid approximately $1,012 million in cash.
203
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
The following table summarizes the preliminary purchase price allocation for the EPL Acquisition as of June 3, 2014 (in thousands):
EPL Historical | Fair Value Adjustment | Total | ||||||||||
(Unaudited) | ||||||||||||
Current assets (excluding deferred income taxes) | $ | 301,592 | $ | 1,274 | $ | 302,866 | ||||||
Oil and natural gas properties(a) | ||||||||||||
Evaluated (Including net ARO assets) | 1,919,699 | 112,624 | 2,032,323 | |||||||||
Unevaluated | 41,896 | 859,886 | 901,782 | |||||||||
Other property and equipment | 7,787 | — | 7,787 | |||||||||
Other assets | 16,227 | (9,002 | ) | 7,225 | ||||||||
Current liabilities (excluding ARO) | (314,649 | ) | (2,058 | ) | (316,707 | ) | ||||||
ARO (current and long-term) | (260,161 | ) | (13,211 | ) | (273,372 | ) | ||||||
Debt (current and long-term) | (973,440 | ) | (52,967 | ) | (1,026,407 | ) | ||||||
Deferred income taxes(b) | (118,359 | ) | (340,645 | ) | (459,004 | ) | ||||||
Other long-term liabilities | (2,242 | ) | 797 | (1,445 | ) | |||||||
Total fair value, excluding goodwill | 618,350 | 556,698 | 1,175,048 | |||||||||
Goodwill(c),(d) | — | 329,293 | 329,293 | |||||||||
Less cash acquired | — | — | 206,075 | |||||||||
Total purchase price | $ | 618,350 | $ | 885,991 | $ | 1,298,266 |
(a) | EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy. |
(b) | Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit). |
(c) | See Note 4 — Goodwill within these quarterly consolidated financial statements for more information regarding goodwill impairment at December 31, 2014. |
(d) | On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million; accordingly the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill. |
In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to, quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates; and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to
204
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.
The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.
The fair value estimates of the oil and natural gas properties and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.
The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, that enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 — Goodwill within these quarterly consolidated financial statements for more information regarding the impairment of goodwill at December 31, 2014.
In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the quarter ended December 31, 2014, our Consolidated Statement of Operations includes EPL’s operating revenues and net loss of $155.6 million and $275.5 million. For the six months ended December 31, 2014, our Consolidated Statement of Operations includes EPL’s operating revenues and net loss of $349.8 million and $301.7 million.
The following supplemental unaudited pro forma financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on the historical consolidated statements of income of Energy XXI and EPL for the three and six months ended December 31, 2013 (in thousands, except per share amounts).
Three Months Ended December 31, 2013 | Six Months Ended December 31, 2013 | |||||||
Revenues | $ | 424,053 | $ | 919,430 | ||||
Net income (loss) | (23,071 | ) | (8,413 | ) | ||||
Net income (loss) available to Energy XXI common stockholders | (25,943 | ) | (14,158 | ) | ||||
Net income (loss) per share available to Energy XXI common stockholders: | ||||||||
Basic | $ | (0.27 | ) | $ | (0.14 | ) | ||
Diluted | $ | (0.27 | ) | $ | (0.14 | ) |
205
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
The above supplemental unaudited pro forma financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments for the three and six months ended December 31, 2013, were the following:
a. | Exclude $13.6 million and $17.0 million, respectively, of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting. |
b. | Increase DD&A expense by $26.6 million and $44.7 million, respectively, for the EPL properties to correspond with EXXI’s full cost method of accounting. |
c. | Increase interest expense by $13.1 million and $26.2 million, respectively, to reflect interest on the $650 million 6.875% Senior Notes and on additional borrowings under EXXI’s revolving credit facility. Decrease interest expense $3.3 million and $6.6 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million face value of EPL’s 8.25% Senior Notes assumed in the EPL acquisition. |
Sales of Oil and Natural Gas properties interests
On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned indirect subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million.
Note 4 — Goodwill
ASC 350,Intangibles — Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed as of the last day of the fourth quarter each fiscal year.
Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.
At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test, which led
206
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 4 — Goodwill – (continued)
us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.
In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using a weighted average cost of capital. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit are reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Note 5 — Property and Equipment
Property and equipment consists of the following (in thousands):
December 31, 2014 (Restated) | June 30, 2014 (Restated) | |||||||
Oil and gas properties | ||||||||
Proved properties | $ | 9,059,934 | $ | 8,247,352 | ||||
Less: accumulated depreciation, depletion, amortization and impairment | 3,318,218 | 2,985,790 | ||||||
Proved properties, net | 5,741,716 | 5,261,562 | ||||||
Unevaluated properties | 807,814 | 1,165,701 | ||||||
Oil and gas properties, net | 6,549,530 | 6,427,263 | ||||||
Other property and equipment | 45,709 | 39,272 | ||||||
Less: accumulated depreciation | 21,876 | 19,512 | ||||||
Other property and equipment, net | 23,833 | 19,760 | ||||||
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment | $ | 6,573,363 | $ | 6,447,023 |
The Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL acquisition), exploratory wells in progress, Bureau of Ocean Energy Management (“BOEM”) lease sales and costs to acquire seismic data. Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) amortization over a period of time of not more than four years.
At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties. Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following: 1) the Lomond North project resulted in a successful production test with commercial production expected to commence in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the Blackbeard East project expired. Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the quarter ended December 31, 2014.
207
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 6 — Equity Method Investments
Energy XXI M21K
We own a 20% interest in EXXI M21K which engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”).
Since its inception in February 2012, M21K has completed three acquisitions for aggregate cash consideration of approximately $284.1 million. In July 2012, it acquired oil and gas interests from EP Energy E&P Company, L.P. for approximately $80.4 million. In August 2013, it acquired oil and gas interests from LLOG Exploration Offshore, L.L.C. for approximately $80.8 million. In April 2014, it acquired oil and gas interests from EXXI GOM for approximately $122.9 million.
EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K related to the three acquisitions noted above. Further, EGC, an indirect wholly owned subsidiary of Energy XXI receives a management fee from M21K for providing administrative assistance in carrying out its operations. See Note 15 — Related Party Transactions within these quarterly consolidated financial statements.
The provisions of the M21K Limited Liability Company Agreement (“LLC Agreement”) provide that M21K can make acquisitions subject to the commitment of its partners. While it is envisioned that M21K will be sold eventually to a third party to monetize returns from the investments, the M21K LLC Agreement does provide for a put and a call that can occur starting July 19, 2016, subject to an earlier option if there is a change of control of Energy XXI. Pursuant to the exercise of the put option, we may be required to pay the fair value calculated on the basis of the current proved reserves as determined by a duly appointed reserve engineering firm utilizing then prevailing forward pricing and cost curves, however we will have no obligation to purchase any partnership interests if both: (i) the put value exceeds the lesser of: (a) $100 million; and (b) 20% of the aggregate capital contributions; and (ii) the put right was not triggered by the occurrence of a change of control.
As of December 31, 2014, our investment in EXXI M21K was approximately $27.7 million. We recorded an equity loss of $1.3 million and $0.3 million for the three and six months ended December 31, 2014, respectively. We recorded an equity loss of $2.7 million and $3.6 million for the three and six months ended December 31, 2013, respectively.
Ping Energy XXI Limited (“Ping Energy”)
On October 18, 2013, Energy XXI International Limited (“EXXI International”) amended its Joint Development Agreement (“JDA”) with Ping Energy and increased its ownership interest to 80% from 49%. Effective October 1, 2013, we consolidated the financial results of Ping Energy in our financial statements. In January 2014, EXXI International terminated the JDA with Ping Energy and is in the process of dissolving Ping Energy. We have no present intention to pursue any international opportunities to acquire exploratory, development or producing oil and natural gas properties.
208
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt
Long-term debt consists of the following (in thousands):
December 31, 2014 | June 30, 2014 | |||||||
Revolving Credit Facility | $ | 941,309 | $ | 689,000 | ||||
8.25% Senior Notes due 2018 | 510,000 | 510,000 | ||||||
6.875% Senior Notes due 2024 | 650,000 | 650,000 | ||||||
3.0% Senior Convertible Notes due 2018 | 400,000 | 400,000 | ||||||
7.5% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
7.75% Senior Notes due 2019 | 250,000 | 250,000 | ||||||
9.25% Senior Notes due 2017 | 750,000 | 750,000 | ||||||
4.14% Promissory Note due 2017 | 4,563 | 4,774 | ||||||
Debt premium, 8.25% Senior Notes due 2018(1) | 35,462 | 40,566 | ||||||
Original issue discount, 3.0% Senior Convertible Notes due 2018 | (51,453 | ) | (57,014 | ) | ||||
Derivative instruments premium financing | 20,752 | 21,000 | ||||||
Capital lease obligations | 991 | 1,318 | ||||||
Total debt | 4,011,624 | 3,759,644 | ||||||
Less current maturities | 21,702 | 15,020 | ||||||
Total long-term debt | $ | 3,989,922 | $ | 3,744,624 |
(1) | Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition. |
Maturities of long-term debt as of December 31, 2014 are as follows (in thousands):
Twelve Months Ended December 31, | ||||
2015 | $ | 21,702 | ||
2016 | 735 | |||
2017 | 753,836 | |||
2018 | 1,835,351 | |||
2019 | 250,000 | |||
Thereafter | 1,150,000 | |||
Total | $ | 4,011,624 |
Revolving Credit Facility
The second amended and restated first lien credit agreement (“First Lien Credit Agreement” or “Revolving Credit Facility”) was entered into by EGC in May 2011 and underwent its Ninth Amendment on September 5, 2014. This facility, as amended, has a borrowing base of $1,500 million and lender commitments of $1,700 million and matures on April 9, 2018, provided that the facility will accelerate if the 9.25% Senior Notes are not retired or refinanced by June 15, 2017 or the 8.25% Senior Notes are not retired or refinanced by August 15, 2017. Borrowings are limited to a borrowing base based on oil and gas reserve values which are re-determined on a periodic basis. Currently, the facility bears interest based on the borrowing base usage, at the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 1.75% to 2.75% or an alternate base rate, based on the federal funds effective rate plus applicable margins ranging from 0.75% to 1.75%. The Revolving Credit Facility is secured by mortgages on at least 85% of the value of our proved reserves. Under the First Lien Credit Agreement, EGC is allowed to pay us a limited amount of distributions, subject to certain terms and conditions.
209
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt – (continued)
The First Lien Credit Agreement, as amended, requires the consolidated EGC to maintain certain financial covenants. Specifically, as of the end of each fiscal quarter, EGC may not permit the following: (a) EGC’s total leverage ratio to be more than 4.25 to 1.0 through the quarter ending March 31, 2015 and 4.0 to 1.0 from the quarter ending June 30, 2015 and beyond, (b) EGC’s interest coverage ratio to be less than 3.0 to 1.0, (c) EGC’s current ratio to be less than 1.0 to 1.0, and (d) EGC’s secured debt leverage ratio to be more than 1.75 to 1.0 through the quarter ending March 31, 2015 and 1.5 to 1.0 from the quarter ending June 30, 2015 and beyond (in each case as defined in the First Lien Credit Agreement). In addition, EGC is subject to various other covenants including, but not limited to, those limiting its ability to declare and pay dividends or other payments, its ability to incur debt, restrictions on change of control, the ability to enter into certain hedging agreements, as well as a covenant to maintain John D. Schiller, Jr. in his current executive position, subject to certain exceptions in the event of his death or disability.
As of December 31, 2014, EGC was in compliance with all covenants and had $941.3 million in borrowings and $226.3 million in letters of credit issued under the First Lien Credit Agreement. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with certain covenants under this agreement in certain future periods. We are focused on reducing our leverage and are pursuing arrangements with third parties to monetize certain midstream assets or sell certain non-core oil and gas properties to enable us to further reduce the amount of required capital commitments. We are also evaluating various alternatives with respect to the First Lien Credit Agreement, including other sources of financing, although any such alternative sources of financing likely would be at higher cost than our current Revolving Credit Facility. There can be no assurance any of these discussions or transactions will prove successful. Absent success in these pursuits, a resultant breach of the covenants under the Revolving Credit Facility would cause a default under such facility, potentially resulting in acceleration of all amounts outstanding under the Revolving Credit Facility. Certain payment defaults or an acceleration under our Revolving Credit Facility could cause a cross-default or cross-acceleration of all of our other outstanding indebtedness. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding, we may not have sufficient liquidity to repay all of our outstanding indebtedness.
8.25% Senior Notes Due 2018
On June 3, 2014, EGC assumed the 8.25% senior notes due 2018 (the “8.25% Senior Notes”) in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.
210
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt – (continued)
6.875% Senior Notes Due 2024
On May 27, 2014, EGC issued $650 million face value of 6.875% unsecured senior notes due March 15, 2024 at par (the “6.875% Senior Notes”). Presently, the 6.875% Senior Notes are not registered under the Securities Act of 1933, as amended (the “Securities Act”). However, EGC and its guarantors have agreed, pursuant to a registration rights agreement with the initial purchasers of the 6.875% Senior Notes, to file a registration statement with the Securities and Exchange Commission (“SEC”) with respect to an offer to exchange a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes and use its reasonable best efforts to cause that registration statement to be declared effective within 365 days after the issue date of the 6.875% Senior Notes. On November 25, 2014, we filed a registration statement with the SEC for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. The registration statement was not yet declared effective by the SEC as of January 30, 2015. EGC incurred underwriting and direct offering costs of approximately $11 million which have been capitalized and are being amortized over the life of the 6.875% Senior Notes.
On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.
The indenture governing the 6.875% Senior Notes, among other things, limits EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
3.0% Senior Convertible Notes Due 2018
On November 18, 2013, Energy XXI Ltd sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). Energy XXI Ltd incurred underwriting and direct offering costs of $7.6 million which have been capitalized and are being amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of Energy XXI Ltd, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
211
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt – (continued)
Upon conversion, Energy XXI Ltd will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the conversion obligation is satisfied solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will receive interest payable in cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be.
If holders elect to convert the notes in connection with certain fundamental change transactions described in the indenture governing the 3.0% Senior Convertible Notes, the conversion rate will increase by a number of additional shares determined by reference to the provisions contained in the indenture governing the 3.0% Senior Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of common stock in, such make-whole fundamental change. If holders of common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.
If Energy XXI Ltd undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require Energy XXI Ltd to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.
For accounting purposes, the $400 million aggregate principal amount of 3.0% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3.0% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the original issue discount of $63.4 million is being amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.
7.5% Senior Notes Due 2021
On September 26, 2013, EGC issued $500 million face value of 7.5% unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”). In April 2014, we filed Amendment No. 1 to the registration statement with the SEC for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.
On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued
212
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt – (continued)
and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.
The indenture governing the 7.5% Senior Notes limits, among other things, EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
7.75% Senior Notes Due 2019
On February 25, 2011, EGC issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal amount of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.
The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. EGC incurred underwriting and direct offering costs of $3.1 million which have been capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.
9.25% Senior Notes Due 2017
On December 17, 2010, EGC issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.
The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. EGC incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.
4.14% Promissory Note
In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity in October 2017. This note carries an interest rate of 4.14% per annum.
213
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 7 — Long-Term Debt – (continued)
Derivative Instruments Premium Financing
We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of December 31, 2014 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $20.8 million and $21.0 million, respectively.
Interest Expense
For the three and six months ended December 31, 2014 and 2013, interest expense consisted of the following (in thousands):
Three Months Ended December 31, | Six Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Revolving Credit Facility | $ | 7,482 | $ | 2,326 | $ | 14,375 | $ | 7,545 | ||||||||
8.25% Senior Notes due 2018 | 10,519 | — | 21,038 | — | ||||||||||||
6.875% Senior Notes due 2024 | 11,172 | — | 22,344 | — | ||||||||||||
3.0% Senior Convertible Notes due 2018 | 3,024 | 1,267 | 6,049 | 1,267 | ||||||||||||
7.50% Senior Notes due 2021 | 9,375 | 9,271 | 18,750 | 9,792 | ||||||||||||
7.75% Senior Notes due 2019 | 4,844 | 4,844 | 9,688 | 9,688 | ||||||||||||
9.25% Senior Notes due 2017 | 17,344 | 17,344 | 34,688 | 34,688 | ||||||||||||
4.14% Promissory Note due 2017 | 47 | 52 | 99 | 104 | ||||||||||||
Amortization of debt issue cost – Revolving Credit Facility | 1,080 | 855 | 2,057 | 1,661 | ||||||||||||
Amortization of fair value premium – 8.25% Senior Notes due 2018 | (2,570 | ) | — | (5,104 | ) | — | ||||||||||
Amortization of debt issue cost – 6.875% Senior Notes due 2024 | 282 | — | 563 | — | ||||||||||||
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 | 2,806 | 1,305 | 5,561 | 1,305 | ||||||||||||
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 | 359 | 31 | 712 | 31 | ||||||||||||
Amortization of debt issue cost – 7.50% Senior Notes due 2021 | 262 | 260 | 525 | 260 | ||||||||||||
Amortization of debt issue cost – 7.75% Senior Notes due 2019 | 97 | 97 | 194 | 194 | ||||||||||||
Amortization of debt issue cost – 9.25% Senior Notes due 2017 | 551 | 552 | 1,103 | 1,104 | ||||||||||||
Derivative instruments financing and other | 227 | 437 | 522 | 687 | ||||||||||||
$ | 66,901 | $ | 38,641 | $ | 133,164 | $ | 68,326 |
Note 8 — Notes Payable
On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of December 31, 2014 was $10.0 million.
214
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 8 — Notes Payable – (continued)
On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015. The balance outstanding as of December 31, 2014 was $2.2 million.
Note 9 — Asset Retirement Obligations
The following table describes the changes to our asset retirement obligations (in thousands):
Balance at June 30, 2014 | $ | 559,834 | ||
Liabilities incurred and true-up to liabilities settled | 21,912 | |||
Liabilities settled | (53,960 | ) | ||
Liabilities sold | (3,307 | ) | ||
Accretion expense | 25,617 | |||
Total balance at December 31, 2014 | 550,096 | |||
Less current portion | 79,573 | |||
Long-term balance at December 31, 2014 | $ | 470,523 |
Note 10 — Derivative Financial Instruments
We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue on the consolidated statements of operations.
With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.
Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.
215
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 10 — Derivative Financial Instruments – (continued)
The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.
Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts keeping one natural gas contract intact.
As of December 31, 2014, we had the following net open crude oil derivative positions:
Weighted Average Contract Price | ||||||||||||||||||||||||||||
Remaining Contract Term | Type of Contract | Index | Volumes (MBbls) | Collars/Put Spreads | ||||||||||||||||||||||||
Sub Floor | Floor | Ceiling | ||||||||||||||||||||||||||
January 2015 – December 2015 | Three-Way Collars | Oil-Brent-IPE | 3,650 | $ | 71.00 | $ | 91.00 | $ | 113.75 | |||||||||||||||||||
January 2015 – December 2015 | Collars | ARGUS-LLS | 1,825 | 80.00 | 123.38 | |||||||||||||||||||||||
January 2015 – December 2015 | Puts | NYMEX-WTI | 405 | 86.11 | ||||||||||||||||||||||||
January 2015 – December 2015 | Put Spreads | ARGUS-LLS | 2,555 | 70.00 | 80.00 | |||||||||||||||||||||||
January 2015 – December 2015 | Collars | NYMEX-WTI | 548 | 75.00 | 85.00 | |||||||||||||||||||||||
January 2015 – December 2015 | Bought Put | NYMEX-WTI | 1,593 | 89.15 | ||||||||||||||||||||||||
January 2015 – December 2015 | Sold Put | NYMEX-WTI | (1,593 | ) | (89.15 | ) | ||||||||||||||||||||||
January 2016 – December 2016 | Collars | NYMEX-WTI | 732 | 70.00 | 90.55 |
As of December 31, 2014, we had the following net open natural gas derivative position:
Remaining Contract Term | Type of Contract | Index | Volumes (MMBtu) | Swaps Fixed Price | ||||||||||||
January 2015 – December 2015 | Swaps | NYMEX-HH | 1,570 | $ | 4.31 |
The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):
Asset Derivative Instruments | Liability Derivative Instruments | |||||||||||||||||||||||||||||||
December 31, 2014 | June 30, 2014 | December 31, 2014 | June 30, 2014 | |||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||||||||||||||||||
Derivative financial instruments | Current | $ | 287,172 | Current | $ | 17,380 | Current | $ | 137,146 | Current | $ | 47,912 | ||||||||||||||||||||
Non-Current | 10,670 | Non-Current | 9,595 | Non-Current | 2,293 | Non-Current | 10,866 | |||||||||||||||||||||||||
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement | 297,842 | 26,975 | 139,439 | 58,778 | ||||||||||||||||||||||||||||
Derivative financial instruments | Current | (137,146 | ) | Current | (15,955 | ) | Current | (137,146 | ) | Current | (15,955 | ) | ||||||||||||||||||||
Non-Current | (2,293 | ) | Non-Current | (6,560 | ) | Non-Current | (2,293 | ) | Non-Current | (6,560 | ) | |||||||||||||||||||||
Gross amounts offset in Balance Sheets | (139,439 | ) | (22,515 | ) | (139,439 | ) | (22,515 | ) | ||||||||||||||||||||||||
Net amounts presented in Balance Sheets | Current | 150,026 | Current | 1,425 | Current | — | Current | 31,957 | ||||||||||||||||||||||||
Non-Current | 8,377 | Non-Current | 3,035 | Non-Current | — | Non-Current | 4,306 | |||||||||||||||||||||||||
$ | 158,403 | $ | 4,460 | $ | — | $ | 36,263 |
216
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 10 — Derivative Financial Instruments – (continued)
The following table presents information about the components of the gain (loss) on derivative instruments (in thousands).
Gain (loss) on derivative financial instruments | Three Months Ended December 31, | Six Months Ended December 31, | ||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Cash Settlements, net of amortization of purchased put premiums | $ | 44,954 | $ | (1,801 | ) | $ | 43,220 | $ | (4,699 | ) | ||||||
Proceeds from monetizations, net | 25,873 | — | 29,236 | — | ||||||||||||
Change in fair value | 120,635 | (19,150 | ) | 175,731 | (46,655 | ) | ||||||||||
Total gain (loss) on derivative financial instruments | $ | 191,462 | $ | (20,951 | ) | $ | 248,187 | $ | (51,354 | ) |
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At December 31, 2014, we had no deposits for collateral with our counterparties.
Note 11 — Income Taxes
We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods. However, in the current period, we have recorded a goodwill impairment charge of $329 million (see Note 4 — Goodwill within these quarterly consolidated financial statements). In light of the form of the transaction related to the acquisition of EPL on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition during fiscal year 2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes. Currently, our estimated annual effective tax/(benefit) rate is approximately 30.5% excluding the effect of the goodwill impairment charge. For purposes of computing our interim provision (benefit) for income taxes, the goodwill impairment charge is treated as a discrete item in the quarter in which it occurred. Our actual effective tax/(benefit) rates for the three and six months ended December 31, 2014 were (17)% and (30)%, respectively. The variance from the U.S. statutory rate of 35% is primarily due to two elements: (i) the impairment of goodwill and (ii) a decrease to the statutory rate due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit. Additionally, our Bermuda companies continue to record income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalent) accrued on indebtedness of the U.S. companies held by the Bermuda companies. We have accrued an additional withholding obligation of $5.2 million for the six months ended December 31, 2014.
Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and EGC will not file a combined nor consolidated Louisiana income tax return. Our valuation allowance of $22.5 million relates to Energy XXI’s separate company Louisiana net operating loss (“NOL”) carryovers that we do not currently believe, on a more likely-than-not basis, will be realized in future years due to the current focus on offshore operations. No valuation allowance has been (or is expected to be) recorded with respect to any Louisiana NOLs generated by EPL, or on consolidated U.S. federal NOL carryovers. Management believes that there is sufficient future taxable income available arising from the future reversal of existing temporary differences recorded due to the excess of the book carrying value of oil and gas properties
217
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 11 — Income Taxes – (continued)
over their corresponding tax bases. Management is not relying on other sources of taxable income in concluding that no valuation allowance is needed on EPL’s Louisiana NOLs or consolidated U.S federal NOL carryovers.
During the six months ended December 31, 2014, we made cash withholding tax payments of $0.6 million on management fees paid to our Bermuda entities. While we have not made a cash income tax payment during the six months ended December 31, 2014, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We expect any AMT payment to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.
On May 13, 2014, the U.S. Internal Revenue Service (“IRS”) notified us of their intent to examine the Company’s U.S. federal income tax return (Form 1120) for the year ended June 30, 2013. Subsequently, on October 16, 2014, the IRS notified us that their review was complete and that they were proposing no changes for the tax year ended June 30, 2013. We received final, formal notification from the IRS dated January 12, 2015 that their review was complete and no changes were made to the reported tax for the tax year ended June 30, 2013.
Note 12 — Stockholders’ Equity
Common Stock
Our common stock trades on the NASDAQ under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.
At the Annual General Meeting of our Shareholders held on November 4, 2014, our Shareholders approved changing the name of the Company from Energy XXI (Bermuda) Limited to Energy XXI Ltd and authorized our Board of Directors, at its discretion, to effect a cancellation of the admission of our common shares, par value $0.005 per share to the Alternative Investment Market of the London Stock Exchange (“AIM”). We successfully delisted from AIM on December 15, 2014 but continue to be listed on the NASDAQ.
We paid quarterly cash dividends of $0.12 per share to holders of our common stock during the three and six months ended December 31, 2014 and 2013.
Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, through June 30, 2014, we paid $166.8 million to repurchase 6,639,363 shares of our common stock at a weighted average price per share, excluding fees, of $25.14. As of December 31, 2014, $83.2 million remains available for repurchase under the share repurchase program. We do not intend to repurchase any additional shares of our common stock at this time.
In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, 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.
In February 2014, we retired 2,087,126 shares of our common stock, resulting in 7,329,100 shares of common stock being held in treasury. On June 3, 2014, we reissued the entire 7,329,100 shares of common stock in treasury as part of our common stock issued to EPL stockholders upon merger.
218
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 12 — Stockholders’ Equity – (continued)
As discussed in Note 7 — Long-Term Debt in the Notes to these quarterly consolidated financial statements, in November 2013, we sold $400 million of 3.0% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3.0% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital.
As discussed in Note 3 — Acquisitions and Dispositions in the Notes to these quarterly consolidated financial statements, upon closing of the EPL Acquisition, we issued 23,320,955 shares of our common stock, including the treasury shares, as noted above, as part of the Merger Consideration.
Preferred Stock
Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our board of directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.
Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year.
Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of our common stock as determined on the second trading day immediately prior to the record date for such dividend.
The 5.625% Preferred Stock is convertible into 9.8353 shares of the Company’s common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 5.625% Preferred Stock Certificate of Designation. On or after December 15, 2013, the Company may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price.
The 7.25% Preferred Stock is convertible into 8.77192 shares of the Company’s common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 7.25% Preferred Stock Certificate of Designation. On or after December 15, 2014, the Company may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 150% of the then-prevailing conversion price.
Conversions of Preferred Stock
During the six months ended December 31, 2014, we canceled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the six months ended December 31, 2014, we also canceled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share.
During the six months ended December 31, 2013, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share.
219
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 13 — Supplemental Cash Flow Information
The following table presents our supplemental cash flow information (in thousands):
Six Months Ended December 31, | ||||||||
2014 | 2013 | |||||||
Cash paid for interest | $ | 117,342 | $ | 60,917 | ||||
Cash paid for income taxes | 560 | 3,122 |
The following table presents our non-cash investing and financing activities (in thousands):
Six Months Ended December 31, | ||||||||
2014 | 2013 | |||||||
Financing of insurance premiums | $ | 2,148 | $ | 2,355 | ||||
Derivative instruments premium financing | 7,305 | 3,493 | ||||||
Additions to property and equipment by recognizing asset retirement obligations | 21,912 | 28,050 |
Note 14 — Employee Benefit Plans
The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We maintain an incentive and retention program for our employees. Participation shares (or “Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Restricted Stock Units.
Performance Units
For fiscal 2014, 2013 and 2012, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.
Time-Based Performance Units. The amount due to the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal years 2012, 2013 and 2014 grants, the initial stock prices were $33.20, $24.50 and $22.48, respectively.
TSR Performance-Based Units. For each 2014, 2013 and 2012 TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.
In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period for the 2014, 2013 and 2012 grants.
At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash. The July 21, 2014 vesting of the July 21, 2013, 2012 and 2011 Performance Unit awards were settled 50% in common stock and future vesting of the Performance Units may be settled in
220
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 14 — Employee Benefit Plans – (continued)
stock at the discretion of our board of directors. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.
Changes for Fiscal 2015 Performance Unit Grants. For the performance unit awards granted in fiscal 2015, the Remuneration Committee of the Board of Directors has determined to change the performance measure within the Incentive Plan from absolute TSR to relative TSR compared to a performance peer group. Under this plan, executives will receive no payout for TSR performance below the 25th percentile, a 50% payout for TSR performance at the 25th percentile, a 100% payout for TSR performance at the median, and 200% payout for performance at or above the 75th percentile. Payouts under this plan will be capped at target if absolute total shareholder return is negative. In addition, the Remuneration Committee has decided to eliminate the use of a $5 notional unit and instead will denominate units based on the stock price on the grant date. The Remuneration Committee also decided to eliminate the make-up feature for the fiscal 2015 awards. The awards for fiscal 2015 have continued to be granted 25% in the form of Time-Based Performance Unit awards and 75% in the form of TSR Performance-Based Unit awards.
We recognized compensation expense (benefit) related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):
Three Months Ended December 31, | Six Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Restricted Stock Units | $ | 3,008 | $ | 2,893 | $ | 3,978 | $ | 8,329 | ||||||||
Performance Units | (433 | ) | 476 | (5,608 | ) | 12,828 | ||||||||||
Total compensation expense (benefit) recognized | $ | 2,575 | $ | 3,369 | $ | (1,630 | ) | $ | 21,157 |
As of December 31, 2014, we had 2,452,642 unvested Restricted Stock Units and 2,469,250 Time-Based Performance Units and 822,000 TSR Performance Based Units.
Non-Executive Director Compensation. On November 7, 2011, the Remuneration Committee approved the director compensation program which provides for an annual stock award of $175,000 worth of shares. The equity retainer is paid in Common Shares in an amount equivalent to $175,000 using our closing stock price on the date of the Annual General Meeting, which represents the grant date fair value computed in accordance with FASB Accounting Standards Codification Topic 718. For the fiscal year 2015, each director (except our two recently appointed directors) was awarded 26,396 Common Shares based on a $6.63 closing price on the date of the 2014 Annual General Meeting. Our two recently appointed directors were awarded a pro-rated amount based on their service as directors beginning on December 15, 2014, which awards totaled 63,406 Common Shares each based on a $2.45 closing price on the date of appointment of December 15, 2014. The shares will vest on the date of the 2015 Annual General Meeting.
Note 15 — Related Party Transactions
We have a 20% interest in EXXI M21K and account for this investment using the equity method. EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 6 — Equity Method Investments within these quarterly consolidated financial statements.
We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for EP Energy Property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million. For these guarantees, M21K has
221
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 15 — Related Party Transactions – (continued)
agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the three and six months ended December 31, 2014, we have received $1.0 million and $1.9 million, respectively, related to such guarantees. For the three and six months ended December 31, 2013, we received $0.8 million and $1.4 million, respectively, related to such guarantees.
Prior to the LLOG Exploration acquisition, EGC received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties were purchased on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three and six months ended December 31, 2014, EGC received management fees of $0.5 million and $1.4 million, respectively. For the three and six months ended December, 31, 2013, EGC received management fees of $1.1 million and $1.8 million, respectively.
On April 1, 2014, EXXI GOM sold its interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, it sold 100% of its interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions within these quarterly consolidated financial statements.
Note 16 — Earnings (Loss) per Share
Basic earnings (loss) per share of common stock is computed by dividing net income (loss) available for common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings (loss) per share (“EPS”) (in thousands, except per share data):
Three Months Ended December 31, | Six Months Ended December 31, | |||||||||||||||
2014 (Restated) | 2013 (Restated) | 2014 (Restated) | 2013 (Restated) | |||||||||||||
Net income (loss) | $ | (275,963 | ) | $ | 1,928 | $ | (248,773 | ) | $ | 27,210 | ||||||
Preferred stock dividends | 2,870 | 2,872 | 5,742 | 5,745 | ||||||||||||
Net income (loss) available for common stockholders | $ | (278,833 | ) | $ | (944 | ) | $ | (254,515 | ) | $ | 21,465 | |||||
Weighted average shares outstanding for basic EPS | 93,993 | 73,964 | 93,913 | 74,873 | ||||||||||||
Add dilutive securities | — | — | — | 83 | ||||||||||||
Weighted average shares outstanding for diluted EPS | 93,993 | 73,964 | 93,913 | 74,956 | ||||||||||||
Earnings (loss) per share | ||||||||||||||||
Basic | $ | (2.97 | ) | $ | (0.01 | ) | $ | (2.71 | ) | $ | 0.29 | |||||
Diluted | $ | (2.97 | ) | $ | (0.01 | ) | $ | (2.71 | ) | $ | 0.29 |
For the three months ended December 31, 2014, 8,542,361 and 8,543,120 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect. For the three months ended December 31, 2013, 8,246,990 common stock equivalents were excluded from the diluted average shares due to an anti-dilutive effect.
222
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 17 — Commitments and Contingencies
Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.
Litigation Related to 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 alleged 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 provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) EPL’s directors allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the merger agreement rescinded and also sought damages and attorneys’ fees.
On January 16, 2015, plaintiffs filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.
Note 18 — Fair Value of Financial Instruments
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
• | Level 1 — quoted prices in active markets for identical assets or liabilities. |
• | Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). |
• | Level 3 — unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. |
For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the
223
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 18 — Fair Value of Financial Instruments – (continued)
fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.
Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 10 — Derivative Financial Instruments within these quarterly consolidated financial statements.
The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units.
During the six months ended December 31, 2014, we did not have any transfers from or to Level 3. The following table sets forth our Level 1 and Level 2 financial assets and liabilities that are accounted for at fair value on a recurring basis (in thousands):
Level 1 | Level 2 | |||||||||||||||
As of December 31, 2014 | As of June 30, 2014 | As of December 31, 2014 | As of June 30, 2014 | |||||||||||||
Assets: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 297,842 | $ | 26,975 | ||||||||
Liabilities: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 139,439 | $ | 58,778 | ||||||||
Restricted stock units | 1,355 | 9,425 | — | — | ||||||||||||
Time-based performance units | 986 | 3,698 | — | — | ||||||||||||
Total liabilities | $ | 2,341 | $ | 13,123 | $ | 139,439 | $ | 58,778 |
The following table sets forth the carrying values and estimated fair values of our long-term indebtedness which are classified as Level 2 financial instruments (in thousands):
December 31, 2014 | June 30, 2014 | |||||||||||||||
Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | |||||||||||||
Revolving credit facility | $ | 941,309 | $ | 941,309 | $ | 689,000 | $ | 689,000 | ||||||||
8.25% Senior Notes due 2018 | 545,462 | 416,290 | 550,566 | 545,700 | ||||||||||||
6.875% Senior Notes due 2024 | 650,000 | 359,130 | 650,000 | 663,000 | ||||||||||||
3.0% Senior Convertible Notes due 2018 | 348,547 | 112,000 | 342,986 | 396,780 | ||||||||||||
7.5% Senior Notes due 2021 | 500,000 | 276,450 | 500,000 | 541,250 | ||||||||||||
7.75% Senior Notes due 2019 | 250,000 | 152,750 | 250,000 | 269,480 | ||||||||||||
9.25% Senior Notes due 2017 | 750,000 | 502,500 | 750,000 | 806,630 | ||||||||||||
$ | 3,985,318 | $ | 2,760,429 | $ | 3,732,552 | $ | 3,911,840 |
224
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 18 — Fair Value of Financial Instruments – (continued)
The following table describes the changes in our Level 3 financial instruments (in thousands):
Three Months Ended December 31, | Six Months Ended December 31, | |||||||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||||||
Liabilities: | ||||||||||||||||
Performance-based performance units | ||||||||||||||||
Balance at beginning of period | $ | 841 | $ | 10,636 | $ | 6,910 | $ | 6,778 | ||||||||
Vested | — | — | — | (7,188 | ) | |||||||||||
Grants charged to general and administrative expense | (732 | ) | (559 | ) | (6,801 | ) | 10,487 | |||||||||
Balance at end of period | $ | 109 | $ | 10,077 | $ | 109 | $ | 10,077 |
Note 19 — Prepayments and Accrued Liabilities
Prepayments and accrued liabilities consist of the following (in thousands):
December 31, 2014 | June 30, 2014 | |||||||
Prepaid expenses and other current assets | ||||||||
Advances to joint interest partners | $ | 8,477 | $ | 10,336 | ||||
Insurance | 16,993 | 37,088 | ||||||
Inventory | 7,030 | 7,020 | ||||||
Royalty deposit | 10,263 | 12,262 | ||||||
Other | 7,415 | 5,824 | ||||||
Total prepaid expenses and other current assets | $ | 50,178 | $ | 72,530 | ||||
Accrued liabilities | ||||||||
Advances from joint interest partners | 2,961 | 2,667 | ||||||
Employee benefits and payroll | 18,690 | 43,480 | ||||||
Interest payable | 36,764 | 26,490 | ||||||
Accrued hedge payable | — | 7,874 | ||||||
Undistributed oil and gas proceeds | 23,988 | 34,473 | ||||||
Severance taxes payable | 1,510 | 8,014 | ||||||
Other | 7,752 | 10,528 | ||||||
Total accrued liabilities | $ | 91,665 | $ | 133,526 |
Note 20 — Restatement of Previously Issued Consolidated Financial Statements
Prior to the issuance of this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the
225
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.
The effects of the restatement on our consolidated financial statements are summarized below:
• | Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and |
• | Resulting adjustments required to deferred income taxes and income tax expense (benefit). |
While these non-cash reclassifications impact revenues, net income (loss) in each period, net income (loss) attributable to common stockholders, and net income (loss) per common share, as well as total stockholders’ equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:
As of December 31, 2014 | As of June 30, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Total Current Assets | $ | 465,431 | $ | — | $ | 465,431 | $ | 457,759 | $ | — | $ | 457,759 | ||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | 6,642,565 | (93,035 | ) | 6,549,530 | 6,524,602 | (97,339 | ) | 6,427,263 | ||||||||||||||||
Other property and equipment | 23,833 | — | 23,833 | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | 6,666,398 | (93,035 | ) | 6,573,363 | 6,544,362 | (97,339 | ) | 6,447,023 | ||||||||||||||||
Total Other Assets | 92,214 | — | 92,214 | 436,715 | — | 436,715 | ||||||||||||||||||
Total Assets | $ | 7,224,043 | $ | (93,035 | ) | $ | 7,131,008 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 | ||||||||||
Total Current Liabilities | $ | 517,683 | $ | — | $ | 517,683 | $ | 699,895 | $ | — | $ | 699,895 | ||||||||||||
Deferred Income Taxes | 713,736 | (31,673 | ) | 682,063 | 701,038 | (34,069 | ) | 666,969 | ||||||||||||||||
Other Non-Current Liabilities | 4,469,074 | — | 4,469,074 | 4,240,073 | — | 4,240,073 | ||||||||||||||||||
Total Liabilities | 5,700,493 | (31,673 | ) | 5,668,820 | 5,641,006 | (34,069 | ) | 5,606,937 | ||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | 1 | — | 1 | 1 | — | 1 | ||||||||||||||||||
Common stock | 471 | — | 471 | 468 | — | 468 | ||||||||||||||||||
Additional paid-in capital | 1,842,152 | — | 1,842,152 | 1,837,462 | — | 1,837,462 | ||||||||||||||||||
Accumulated deficit | (428,200 | ) | 47,764 | (380,436 | ) | (19,626 | ) | (83,745 | ) | (103,371 | ) | |||||||||||||
Accumulated other comprehensive loss, net of income taxes | 109,126 | (109,126 | ) | — | (20,475 | ) | 20,475 | — | ||||||||||||||||
Total Stockholders’ Equity | 1,523,550 | (61,362 | ) | 1,462,188 | 1,797,830 | (63,270 | ) | 1,734,560 | ||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 7,224,043 | $ | (93,035 | ) | $ | 7,131,008 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 |
226
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Three Months Ended December 31, 2014 | Three Months Ended December 31, 2013 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands, except share information) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | 324,655 | $ | (44,947 | ) | $ | 279,708 | $ | 262,230 | $ | 1,397 | $ | 263,627 | |||||||||||
Natural gas sales | 33,100 | (1,299 | ) | 31,801 | 34,586 | (3,448 | ) | 31,138 | ||||||||||||||||
Gain (loss) on derivative financial instruments | — | 191,462 | 191,462 | — | (20,951 | ) | (20,951 | ) | ||||||||||||||||
Total Revenues | 357,755 | 145,216 | 502,971 | 296,816 | (23,002 | ) | 273,814 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 177,333 | (2,178 | ) | 175,155 | 103,513 | (2,357 | ) | 101,156 | ||||||||||||||||
(Gain) loss on derivative financial instruments | (886 | ) | 886 | — | 5,722 | (5,722 | ) | — | ||||||||||||||||
All other costs and expenses | 496,236 | — | 496,236 | 126,079 | — | 126,079 | ||||||||||||||||||
Total Costs and Expenses | 672,683 | (1,292 | ) | 671,391 | 235,314 | (8,079 | ) | 227,235 | ||||||||||||||||
Operating Income | (314,928 | ) | 146,508 | (168,420 | ) | 61,502 | (14,923 | ) | 46,579 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Loss from equity method investees | (1,619 | ) | 344 | (1,275 | ) | (2,621 | ) | (105 | ) | (2,726 | ) | |||||||||||||
Other income, net | 991 | — | 991 | 913 | — | 913 | ||||||||||||||||||
Interest expense | (66,901 | ) | — | (66,901 | ) | (38,641 | ) | — | (38,641 | ) | ||||||||||||||
Total Other Expense, net | (67,529 | ) | 344 | (67,185 | ) | (40,349 | ) | (105 | ) | (40,454 | ) | |||||||||||||
Income Before Income Taxes | (382,457 | ) | 146,852 | (235,605 | ) | 21,153 | (15,028 | ) | 6,125 | |||||||||||||||
Income Tax Expense (Benefit) | (8,578 | ) | 48,936 | 40,358 | 10,658 | (6,461 | ) | 4,197 | ||||||||||||||||
Net Income | (373,879 | ) | 97,916 | (275,963 | ) | 10,495 | (8,567 | ) | 1,928 | |||||||||||||||
Preferred Stock Dividends | 2,870 | — | 2,870 | 2,872 | — | 2,872 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | (376,749 | ) | $ | 97,916 | $ | (278,833 | ) | $ | 7,623 | $ | (8,567 | ) | $ | (944 | ) | ||||||||
Earnings per Share | ||||||||||||||||||||||||
Basic | $ | (4.01 | ) | $ | (2.97 | ) | $ | 0.10 | $ | (0.01 | ) | |||||||||||||
Diluted | $ | (4.01 | ) | $ | (2.97 | ) | $ | 0.10 | $ | (0.01 | ) | |||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||||||
Basic | 93,993 | 93,993 | 73,964 | 73,964 | ||||||||||||||||||||
Diluted | 93,993 | 93,993 | 74,053 | 73,964 | ||||||||||||||||||||
Net Income | $ | (373,879 | ) | $ | 97,916 | $ | (275,963 | ) | $ | 10,495 | $ | (8,567 | ) | $ | 1,928 | |||||||||
Other Comprehensive Loss | ||||||||||||||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||||||||||||||
Unrealized change in fair value net of ineffective portion | 195,607 | (195,607 | ) | — | (9,028 | ) | 9,028 | — | ||||||||||||||||
Effective portion reclassified to earnings during the period | (51,225 | ) | 51,225 | — | (8,357 | ) | 8,357 | — | ||||||||||||||||
Total Other Comprehensive Loss | 144,382 | (144,382 | ) | — | (17,385 | ) | 17,385 | — | ||||||||||||||||
Income Tax Expense (Benefit) | 50,534 | (50,534 | ) | — | (6,085 | ) | 6,085 | |||||||||||||||||
Net Other Comprehensive Loss | 93,848 | (93,848 | ) | — | (11,300 | ) | 11,300 | — | ||||||||||||||||
Comprehensive Income | $ | (280,031 | ) | $ | 4,068 | $ | (275,963 | ) | $ | (805 | ) | $ | 2,733 | $ | 1,928 |
227
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Six Months Ended December 31, 2014 | Six Months Ended December 31, 2013 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands, except share information) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | 693,156 | $ | (43,293 | ) | $ | 649,863 | $ | 551,459 | $ | 3,134 | $ | 554,593 | |||||||||||
Natural gas sales | 67,830 | (1,468 | ) | 66,362 | 69,949 | (6,227 | ) | 63,722 | ||||||||||||||||
Gain (loss) on derivative financial instruments | — | 248,187 | 248,187 | — | (51,354 | ) | (51,354 | ) | ||||||||||||||||
Total Revenues | 760,986 | 203,426 | 964,412 | 621,408 | (54,447 | ) | 566,961 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 338,599 | (4,304 | ) | 334,295 | 203,729 | (4,913 | ) | 198,816 | ||||||||||||||||
(Gain) loss on derivative financial instruments | (4,169 | ) | 4,169 | — | 7,163 | (7,163 | ) | — | ||||||||||||||||
All other costs and expenses | 690,345 | — | 690,345 | 249,583 | — | 249,583 | ||||||||||||||||||
Total Costs and Expenses | 1,024,775 | (135 | ) | 1,024,640 | 460,475 | (12,076 | ) | 448,399 | ||||||||||||||||
Operating Income | (263,789 | ) | 203,561 | (60,228 | ) | 160,933 | (42,371 | ) | 118,562 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Loss from equity method investees | (738 | ) | 422 | (316 | ) | (4,414 | ) | (419 | ) | (4,833 | ) | |||||||||||||
Other income, net | 1,942 | — | 1,942 | 1,435 | — | 1,435 | ||||||||||||||||||
Interest expense | (133,164 | ) | — | (133,164 | ) | (68,326 | ) | — | (68,326 | ) | ||||||||||||||
Total Other Expense, net | (131,960 | ) | 422 | (131,538 | ) | (71,305 | ) | (419 | ) | (71,724 | ) | |||||||||||||
Income Before Income Taxes | (395,749 | ) | 203,983 | (191,766 | ) | 89,628 | (42,790 | ) | 46,838 | |||||||||||||||
Income Tax Expense (Benefit) | (15,467 | ) | 72,474 | 57,007 | 35,994 | (16,366 | ) | 19,628 | ||||||||||||||||
Net Income | (380,282 | ) | 131,509 | (248,773 | ) | 53,634 | (26,424 | ) | 27,210 | |||||||||||||||
Preferred Stock Dividends | 5,742 | — | 5,742 | 5,745 | — | 5,745 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | (386,024 | ) | $ | 131,509 | $ | (254,515 | ) | $ | 47,889 | $ | (26,424 | ) | $ | 21,465 | |||||||||
Earnings per Share | ||||||||||||||||||||||||
Basic | $ | (4.11 | ) | $ | (2.71 | ) | $ | 0.64 | $ | 0.29 | ||||||||||||||
Diluted | $ | (4.11 | ) | $ | (2.71 | ) | $ | 0.64 | $ | 0.29 | ||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||||||
Basic | 93,913 | 93,913 | 74,873 | 74,873 | ||||||||||||||||||||
Diluted | 93,913 | 93,913 | 74,956 | 74,956 | ||||||||||||||||||||
Net Income | $ | (380,282 | ) | $ | 131,509 | $ | (248,773 | ) | $ | 53,634 | $ | (26,424 | ) | $ | 27,210 | |||||||||
Other Comprehensive Loss | ||||||||||||||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||||||||||||||
Unrealized change in fair value net of ineffective portion | 252,600 | (252,600 | ) | — | (31,999 | ) | 31,999 | — | ||||||||||||||||
Effective portion reclassified to earnings during the period | (53,214 | ) | 53,214 | — | (15,705 | ) | 15,705 | — | ||||||||||||||||
Total Other Comprehensive Loss | 199,386 | (199,386 | ) | — | (47,704 | ) | 47,704 | — | ||||||||||||||||
Income Tax Expense (Benefit) | 69,785 | (69,785 | ) | — | (16,696 | ) | 16,696 | |||||||||||||||||
Net Other Comprehensive Loss | 129,601 | (129,601 | ) | — | (31,008 | ) | 31,008 | — | ||||||||||||||||
Comprehensive Income | $ | (250,681 | ) | $ | 1,908 | $ | (248,773 | ) | $ | 22,626 | $ | 4,584 | $ | 27,210 |
228
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Six Months Ended December 31, 2014 | Six Months Ended December 31, 2013 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (380,282 | ) | $ | 131,509 | $ | (248,773 | ) | $ | 53,634 | $ | (26,424 | ) | $ | 27,210 | |||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 338,599 | (4,304 | ) | 334,295 | 203,729 | (4,913 | ) | 198,816 | ||||||||||||||||
Goodwill impairment | 329,293 | — | 329,293 | — | — | — | ||||||||||||||||||
Deferred income tax expense (benefit) | (16,027 | ) | 72,474 | 56,447 | 32,872 | (16,367 | ) | 16,505 | ||||||||||||||||
Change in fair value of derivative financial instruments | 23,787 | (199,518 | ) | (175,731 | ) | (364 | ) | 47,019 | 46,655 | |||||||||||||||
Accretion of asset retirement obligations | 25,617 | — | 25,617 | 14,751 | — | 14,751 | ||||||||||||||||||
Loss (income) from equity method investees | 738 | (422 | ) | 316 | 4,414 | 419 | 4,833 | |||||||||||||||||
Amortization and write-off of debt issuance costs and other | 5,615 | — | 5,615 | 4,555 | — | 4,555 | ||||||||||||||||||
Stock-based compensation | 2,632 | — | 2,632 | 3,971 | — | 3,971 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | 33,819 | — | 33,819 | 16,999 | — | 16,999 | ||||||||||||||||||
Prepaid expenses and other current assets | 22,483 | — | 22,483 | 6,219 | — | 6,219 | ||||||||||||||||||
Settlement of asset retirement obligations | (53,960 | ) | — | (53,960 | ) | (34,038 | ) | — | (34,038 | ) | ||||||||||||||
Accounts payable and accrued liabilities | (171,006 | ) | 261 | (170,745 | ) | (45,042 | ) | 266 | (44,776 | ) | ||||||||||||||
Net Cash Provided by Operating Activities | 161,308 | — | 161,308 | 261,700 | — | 261,700 | ||||||||||||||||||
Net Cash Used in Investing Activities | (429,392 | ) | — | (429,392 | ) | (411,555 | ) | — | (411,555 | ) | ||||||||||||||
Net Cash Provided by Financing Activities | 223,562 | — | 223,562 | 507,683 | — | 507,683 | ||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (44,522 | ) | — | (44,522 | ) | 357,828 | — | 357,828 | ||||||||||||||||
Cash and Cash Equivalents, beginning of period | 145,806 | 145,806 | — | — | ||||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 101,284 | $ | 101,284 | $ | 357,828 | $ | 357,828 |
229
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information
Our indirect, 100% wholly owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the above senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s Revolving Credit Facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC requires the issuer and guarantors to file separate financial statements. We meet the conditions in Rule 3-10 to report information about the assets, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to our financial statements, condensed consolidating financial information for the same periods as those presented in our financial statements.
The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, the guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses. The following supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements and should be read in conjunction with our consolidated financial statements and notes thereto included in the this Form 10-K.
230
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
December 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 102,034 | $ | — | $ | — | $ | 1,491 | $ | (2,241 | ) | $ | 101,284 | |||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 76,150 | 33,211 | (6,479 | ) | 102,882 | |||||||||||||||||
Joint interest billings | — | 1,940 | — | 17,194 | (36 | ) | 19,098 | |||||||||||||||||
Other | — | 19,649 | — | 11,459 | (380 | ) | 30,728 | |||||||||||||||||
Prepaid expenses and other current assets | 701 | 22,446 | 213 | 26,818 | — | 50,178 | ||||||||||||||||||
Deferred income taxes | — | — | — | 11,235 | — | 11,235 | ||||||||||||||||||
Derivative financial instruments | — | 148,022 | — | 2,004 | — | 150,026 | ||||||||||||||||||
Total Current Assets | 102,735 | 192,057 | 76,363 | 103,412 | (9,136 | ) | 465,431 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,277,132 | 3,100,214 | 172,184 | 6,549,530 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 23,833 | — | 23,833 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,277,132 | 3,124,047 | 172,184 | 6,573,363 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Derivative financial instruments | — | 8,377 | — | — | — | 8,377 | ||||||||||||||||||
Equity investments | 1,441,436 | 2,434,418 | — | 5,561,605 | (9,409,774 | ) | 27,685 | |||||||||||||||||
Intercompany receivables | 112,374 | 1,939,906 | — | — | (2,052,280 | ) | — | |||||||||||||||||
Restricted cash | — | — | — | 6,024 | — | 6,024 | ||||||||||||||||||
Other assets and debt issuance costs, net | 177,585 | 40,036 | 1 | 3,506 | (171,000 | ) | 50,128 | |||||||||||||||||
Total Other Assets | 1,731,395 | 4,422,737 | 1 | 5,571,135 | (11,633,054 | ) | 92,214 | |||||||||||||||||
Total Assets | $ | 1,834,130 | $ | 4,614,794 | $ | 3,353,496 | $ | 8,798,594 | $ | (11,470,006 | ) | $ | 7,131,008 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 44,753 | $ | 144,630 | $ | 132,514 | $ | (9,329 | ) | $ | 312,568 | |||||||||||
Accrued liabilities | 1,702 | 23,157 | 17,843 | 121,277 | (72,314 | ) | 91,665 | |||||||||||||||||
Notes payable | — | 12,175 | — | — | — | 12,175 | ||||||||||||||||||
Deferred income taxes | — | — | — | — | — | — | ||||||||||||||||||
Asset retirement obligations | — | — | 39,742 | 39,831 | — | 79,573 | ||||||||||||||||||
Current maturities of long-term debt | — | 20,752 | — | — | 950 | 21,702 | ||||||||||||||||||
Total Current Liabilities | 1,702 | 100,837 | 202,215 | 293,622 | (80,693 | ) | 517,683 | |||||||||||||||||
Long-term debt, less current maturities | 348,547 | 2,551,309 | — | 1,262,016 | (171,950 | ) | 3,989,922 | |||||||||||||||||
Deferred income taxes | 21,693 | 190,787 | — | 469,583 | — | 682,063 | ||||||||||||||||||
Asset retirement obligations | — | 50 | 252,156 | 218,317 | — | 470,523 | ||||||||||||||||||
Intercompany payables | — | — | 1,756,216 | 203,457 | (1,959,673 | ) | — | |||||||||||||||||
Other liabilities | — | — | — | 8,629 | — | 8,629 | ||||||||||||||||||
Total Liabilities | 371,942 | 2,842,983 | 2,210,587 | 2,455,624 | (2,212,316 | ) | 5,668,820 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 471 | 1 | — | 12 | (13 | ) | 471 | |||||||||||||||||
Additional paid-in capital | 1,842,152 | 2,072,556 | 273,130 | 7,098,198 | (9,443,884 | ) | 1,842,152 | |||||||||||||||||
Accumulated earnings (deficit) | (380,436 | ) | (300,746 | ) | 869,779 | (755,240 | ) | 186,207 | (380,436 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,462,188 | 1,771,811 | 1,142,909 | 6,342,970 | (9,257,690 | ) | 1,462,188 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 1,834,130 | $ | 4,614,794 | $ | 3,353,496 | $ | 8,798,594 | $ | (11,470,006 | ) | $ | 7,131,008 |
231
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
June 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 135,703 | $ | 3,723 | $ | — | $ | 6,380 | $ | — | $ | 145,806 | ||||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 127,773 | 50,990 | (11,688 | ) | 167,075 | |||||||||||||||||
Joint interest billings | — | 1,833 | — | 11,065 | — | 12,898 | ||||||||||||||||||
Other | 10 | 3,452 | 517 | 1,460 | (1 | ) | 5,438 | |||||||||||||||||
Prepaid expenses and other current assets | 230 | 27,705 | 350 | 44,245 | — | 72,530 | ||||||||||||||||||
Deferred income taxes | — | 27,424 | — | 25,163 | — | 52,587 | ||||||||||||||||||
Derivative financial instruments | — | 1,425 | — | — | — | 1,425 | ||||||||||||||||||
Total Current Assets | 135,943 | 65,562 | 128,640 | 139,303 | (11,689 | ) | 457,759 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,227,584 | 3,197,765 | 1,914 | 6,427,263 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,227,584 | 3,217,525 | 1,914 | 6,447,023 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Goodwill | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Derivative financial instruments | — | 3,035 | — | — | — | 3,035 | ||||||||||||||||||
Equity investments | 1,681,640 | 2,871,756 | — | 2,291,045 | (6,803,798 | ) | 40,643 | |||||||||||||||||
Intercompany receivables | 102,489 | 1,627,931 | — | 80,983 | (1,811,403 | ) | — | |||||||||||||||||
Restricted cash | — | — | 325 | 6,025 | — | 6,350 | ||||||||||||||||||
Other assets and debt issuance costs, net | 178,299 | 42,155 | — | 7,940 | (171,000 | ) | 57,394 | |||||||||||||||||
Total Other Assets | 1,962,428 | 4,544,877 | 325 | 2,715,286 | (8,786,201 | ) | 436,715 | |||||||||||||||||
Total Assets | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 64,533 | $ | 150,909 | $ | 214,215 | $ | (11,881 | ) | $ | 417,776 | |||||||||||
Accrued liabilities | 1,640 | 12,501 | 28,750 | 154,587 | (63,952 | ) | 133,526 | |||||||||||||||||
Notes payable | — | 21,967 | — | — | — | 21,967 | ||||||||||||||||||
Deferred income taxes | 19,185 | — | — | — | (19,185 | ) | — | |||||||||||||||||
Asset retirement obligations | — | — | 39,819 | 39,830 | — | 79,649 | ||||||||||||||||||
Derivative financial instruments | — | 5,517 | — | 26,440 | — | 31,957 | ||||||||||||||||||
Current maturities of long-term debt | — | 14,093 | — | 927 | — | 15,020 | ||||||||||||||||||
Total Current Liabilities | 20,825 | 118,611 | 219,478 | 435,999 | (95,018 | ) | 699,895 | |||||||||||||||||
Long-term debt, less current maturities | 342,986 | 2,305,906 | — | 1,266,732 | (171,000 | ) | 3,744,624 | |||||||||||||||||
Deferred income taxes | — | 177,007 | — | 470,755 | 19,207 | 666,969 | ||||||||||||||||||
Asset retirement obligations | — | 49 | 247,272 | 232,864 | — | 480,185 | ||||||||||||||||||
Derivative financial instruments | — | 2,166 | — | 2,140 | — | 4,306 | ||||||||||||||||||
Intercompany payables | — | — | 1,640,094 | — | (1,640,094 | ) | — | |||||||||||||||||
Other liabilities | — | — | — | 10,958 | — | 10,958 | ||||||||||||||||||
Total Liabilities | 363,811 | 2,603,739 | 2,106,844 | 2,419,448 | (1,886,905 | ) | 5,606,937 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 468 | 1 | 10 | (11 | ) | 468 | ||||||||||||||||||
Additional paid-in capital | 1,837,462 | 2,092,439 | 273,129 | 3,580,005 | (5,945,573 | ) | 1,837,462 | |||||||||||||||||
Accumulated earnings (deficit) | (103,371 | ) | (85,740 | ) | 976,576 | 72,651 | (963,487 | ) | (103,371 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,734,560 | 2,006,700 | 1,249,705 | 3,652,666 | (6,909,071 | ) | 1,734,560 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 |
232
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended December 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 158,883 | $ | 120,825 | $ | — | $ | 279,708 | ||||||||||||
Natural gas sales | — | — | 19,253 | 12,548 | — | 31,801 | ||||||||||||||||||
Gain on derivative financial instruments | — | 169,226 | — | 22,236 | — | 191,462 | ||||||||||||||||||
Total Revenues | — | 169,226 | 178,136 | 155,609 | — | 502,971 | ||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | 86 | 62,828 | 56,452 | — | 119,366 | ||||||||||||||||||
Production taxes | — | 2 | 957 | 1,304 | — | 2,263 | ||||||||||||||||||
Gathering and transportation | — | — | 4,771 | — | — | 4,771 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 98,461 | 89,361 | (12,667 | ) | 175,155 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 6,700 | 6,098 | — | 12,798 | ||||||||||||||||||
Goodwill impairment | — | — | — | 482,598 | (153,305 | ) | 329,293 | |||||||||||||||||
General and administrative expense | 2,348 | 1,939 | 25,655 | (2,197 | ) | — | 27,745 | |||||||||||||||||
Total Costs and Expenses | 2,348 | 2,027 | 199,372 | 633,616 | (165,972 | ) | 671,391 | |||||||||||||||||
Operating Income (Loss) | (2,348 | ) | 167,199 | (21,236 | ) | (478,007 | ) | 165,972 | (168,420 | ) | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | (278,486 | ) | (357,623 | ) | — | (361,702 | ) | 996,536 | (1,275 | ) | ||||||||||||||
Other income (expense) – net | 5,144 | 485 | — | 3,611 | (8,249 | ) | 991 | |||||||||||||||||
Interest expense | (6,188 | ) | (48,273 | ) | (1,419 | ) | (29,324 | ) | 18,303 | (66,901 | ) | |||||||||||||
Total Other Expense | (279,530 | ) | (405,411 | ) | (1,419 | ) | (387,415 | ) | 1,006,590 | (67,185 | ) | |||||||||||||
Income (Loss) Before Income Taxes | (281,878 | ) | (238,212 | ) | (22,655 | ) | (865,422 | ) | 1,172,562 | (235,605 | ) | |||||||||||||
Income Tax Expense (Benefit) | 1,528 | 32,086 | — | 6,744 | — | 40,358 | ||||||||||||||||||
Net Income (Loss) | (283,406 | ) | (270,298 | ) | (22,655 | ) | (872,166 | ) | 1,172,562 | (275,963 | ) | |||||||||||||
Preferred Stock Dividends | 2,870 | — | — | — | — | 2,870 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (286,276 | ) | $ | (270,298 | ) | $ | (22,655 | ) | $ | (872,166 | ) | $ | 1,172,562 | $ | (278,833 | ) |
233
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended December 31, 2013 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 263,627 | $ | — | $ | — | $ | 263,627 | ||||||||||||
Natural gas sales | — | — | 31,138 | — | — | 31,138 | ||||||||||||||||||
Loss on derivative financial instruments | — | (20,951 | ) | — | — | — | (20,951 | ) | ||||||||||||||||
Total Revenues | — | (20,951 | ) | 294,765 | — | — | 273,814 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (613 | ) | 94,402 | — | — | 93,789 | |||||||||||||||||
Production taxes | — | 12 | 1,177 | — | — | 1,189 | ||||||||||||||||||
Gathering and transportation | — | — | 5,978 | — | — | 5,978 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 100,155 | 1,001 | — | 101,156 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 7,425 | — | — | 7,425 | ||||||||||||||||||
General and administrative expense | 1,264 | 522 | 14,641 | 1,271 | — | 17,698 | ||||||||||||||||||
Total Costs and Expenses | 1,264 | (79 | ) | 223,778 | 2,272 | — | 227,235 | |||||||||||||||||
Operating Income (Loss) | (1,264 | ) | (20,872 | ) | 70,987 | (2,272 | ) | — | 46,579 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 2,516 | 57,885 | — | (52,445 | ) | (10,682 | ) | (2,726 | ) | |||||||||||||||
Other income (expense) – net | 5,110 | 487 | — | 72,587 | (77,271 | ) | 913 | |||||||||||||||||
Interest expense | (2,729 | ) | (34,321 | ) | (1,516 | ) | (18,418 | ) | 18,343 | (38,641 | ) | |||||||||||||
Total Other Income (Expense) | 4,897 | 24,051 | (1,516 | ) | 1,724 | (69,610 | ) | (40,454 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 3,633 | 3,179 | 69,471 | (548 | ) | (69,610 | ) | 6,125 | ||||||||||||||||
Income Tax Expense (Benefit) | 1,705 | (3,758 | ) | — | 6,250 | — | 4,197 | |||||||||||||||||
Net Income (Loss) | 1,928 | 6,937 | 69,471 | (6,798 | ) | (69,610 | ) | 1,928 | ||||||||||||||||
Preferred Stock Dividends | 2,872 | — | — | — | — | 2,872 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (944 | ) | $ | 6,937 | $ | 69,471 | $ | (6,798 | ) | $ | (69,610 | ) | $ | (944 | ) |
234
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Six Months Ended December 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 370,723 | $ | 279,140 | $ | — | $ | 649,863 | ||||||||||||
Natural gas sales | — | — | 39,860 | 26,502 | — | 66,362 | ||||||||||||||||||
Gain on derivative financial instruments | — | 204,094 | — | 44,093 | — | 248,187 | ||||||||||||||||||
Total Revenues | — | 204,094 | 410,583 | 349,735 | — | 964,412 | ||||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | — | 148,574 | 113,377 | — | 261,951 | ||||||||||||||||||
Production taxes | — | 16 | 2,078 | 3,262 | — | 5,356 | ||||||||||||||||||
Gathering and transportation | — | — | 13,959 | — | — | 13,959 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 189,525 | 163,844 | (19,074 | ) | 334,295 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 13,338 | 12,279 | — | 25,617 | ||||||||||||||||||
Goodwill impairment | — | — | — | 482,598 | (153,305 | ) | 329,293 | |||||||||||||||||
General and administrative expense | 3,495 | 3,710 | 30,265 | 16,699 | — | 54,169 | ||||||||||||||||||
Total Costs and Expenses | 3,495 | 3,726 | 397,739 | 792,059 | (172,379 | ) | 1,024,640 | |||||||||||||||||
Operating Income (Loss) | (3,495 | ) | 200,368 | 12,844 | (442,324 | ) | 172,379 | (60,228 | ) | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | (247,647 | ) | (295,722 | ) | — | (358,659 | ) | 901,712 | (316 | ) | ||||||||||||||
Other income (expense) – net | 10,316 | 969 | — | 8,960 | (18,303 | ) | 1,942 | |||||||||||||||||
Interest expense | (12,321 | ) | (95,926 | ) | (2,914 | ) | (40,306 | ) | 18,303 | (133,164 | ) | |||||||||||||
Total Other Expense | (249,652 | ) | (390,679 | ) | (2,914 | ) | (390,005 | ) | 901,712 | (131,538 | ) | |||||||||||||
Income (Loss) Before Income Taxes | (253,147 | ) | (190,311 | ) | 9,930 | (832,329 | ) | 1,074,091 | (191,766 | ) | ||||||||||||||
Income Tax Expense (Benefit) | 3,069 | 44,387 | — | 9,551 | — | 57,007 | ||||||||||||||||||
Net Income (Loss) | (256,216 | ) | (234,698 | ) | 9,930 | (841,880 | ) | 1,074,091 | (248,773 | ) | ||||||||||||||
Preferred Stock Dividends | 5,742 | — | — | — | — | 5,742 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (261,958 | ) | $ | (234,698 | ) | $ | 9,930 | $ | (841,880 | ) | $ | 1,074,091 | $ | (254,515 | ) |
235
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Six Months Ended December 31, 2013 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 554,593 | $ | — | $ | — | $ | 554,593 | ||||||||||||
Natural gas sales | — | — | 63,722 | — | — | 63,722 | ||||||||||||||||||
Loss on derivative financial instruments | — | (51,354 | ) | — | — | — | (51,354 | ) | ||||||||||||||||
Total Revenues | — | (51,354 | ) | 618,315 | — | — | 566,961 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (856 | ) | 180,408 | — | — | 179,552 | |||||||||||||||||
Production taxes | — | 27 | 2,560 | — | — | 2,587 | ||||||||||||||||||
Gathering and transportation | — | — | 11,323 | — | — | 11,323 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 197,060 | 1,756 | — | 198,816 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 14,751 | — | — | 14,751 | ||||||||||||||||||
General and administrative expense | 2,888 | 317 | 36,175 | 1,990 | — | 41,370 | ||||||||||||||||||
Total Costs and Expenses | 2,888 | (512 | ) | 442,277 | 3,746 | — | 448,399 | |||||||||||||||||
Operating Income (Loss) | (2,888 | ) | (50,842 | ) | 176,038 | (3,746 | ) | — | 118,562 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 26,117 | 169,089 | — | (6,838 | ) | (193,201 | ) | (4,833 | ) | |||||||||||||||
Other income (expense) – net | 9,833 | 970 | — | 77,075 | (86,443 | ) | 1,435 | |||||||||||||||||
Interest expense | (2,730 | ) | (62,409 | ) | (3,032 | ) | (18,498 | ) | 18,343 | (68,326 | ) | |||||||||||||
Total Other Income (Expense) | 33,220 | 107,650 | (3,032 | ) | 51,739 | (261,301 | ) | (71,724 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 30,332 | 56,808 | 173,006 | 47,993 | (261,301 | ) | 46,838 | |||||||||||||||||
Income Tax Expense (Benefit) | 3,122 | 19,701 | — | (3,195 | ) | — | 19,628 | |||||||||||||||||
Net Income (Loss) | 27,210 | 37,107 | 173,006 | 51,188 | (261,301 | ) | 27,210 | |||||||||||||||||
Preferred Stock Dividends | 5,745 | — | — | — | — | 5,745 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | 21,465 | $ | 37,107 | $ | 173,006 | $ | 51,188 | $ | (261,301 | ) | $ | 21,465 |
236
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Six Months Ended December 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (256,216 | ) | $ | (234,698 | ) | $ | 9,930 | $ | (841,880 | ) | $ | 1,074,091 | $ | (248,773 | ) | ||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 189,525 | 163,844 | (19,074 | ) | 334,295 | |||||||||||||||||
Goodwill impairment | — | — | — | 482,598 | (153,305 | ) | 329,293 | |||||||||||||||||
Deferred income tax expense | 2,508 | 45,562 | — | 8,377 | — | 56,447 | ||||||||||||||||||
Change in fair value of derivative financial instruments | — | (161,075 | ) | — | (14,656 | ) | — | (175,731 | ) | |||||||||||||||
Accretion of asset retirement obligations | — | — | 13,338 | 12,279 | — | 25,617 | ||||||||||||||||||
Loss from equity method investees | 247,647 | 295,722 | — | 358,659 | (901,712 | ) | 316 | |||||||||||||||||
Amortization and write-off of debt issuance costs and other | 6,274 | 4,421 | — | (5,080 | ) | — | 5,615 | |||||||||||||||||
Stock-based compensation | 2,632 | — | — | — | — | 2,632 | ||||||||||||||||||
Changes in operating assets and liabilities | — | |||||||||||||||||||||||
Accounts receivable | 10 | (20,454 | ) | 52,556 | 1,707 | — | 33,819 | |||||||||||||||||
Prepaid expenses and other current assets | (470 | ) | 5,259 | 137 | 17,557 | — | 22,483 | |||||||||||||||||
Settlement of asset retirement obligations | — | — | (53,960 | ) | — | — | (53,960 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | (9,821 | ) | (188,469 | ) | (18,207 | ) | (105,007 | ) | 150,759 | (170,745 | ) | |||||||||||||
Net Cash Provided by (Used in) Operating Activities | (7,436 | ) | (253,732 | ) | 193,319 | 78,398 | 150,759 | 161,308 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (287 | ) | — | — | (287 | ) | ||||||||||||||||
Capital expenditures | — | — | (200,304 | ) | (248,810 | ) | — | (449,114 | ) | |||||||||||||||
Change in equity method investments | — | — | — | 12,642 | — | 12,642 | ||||||||||||||||||
Intercompany investment | — | — | — | 153,000 | (153,000 | ) | — | |||||||||||||||||
Transfers from restricted cash | — | — | 325 | — | — | 325 | ||||||||||||||||||
Proceeds from the sale of properties | — | — | 6,947 | — | — | 6,947 | ||||||||||||||||||
Other | — | — | — | 95 | — | 95 | ||||||||||||||||||
Net Cash (Used in) Investing Activities | — | — | (193,319 | ) | (83,073 | ) | (153,000 | ) | (429,392 | ) | ||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,059 | — | — | — | — | 2,059 | ||||||||||||||||||
Dividends to shareholders – common | (22,548 | ) | — | — | — | — | (22,548 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (5,744 | ) | — | — | — | — | (5,744 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 1,011,948 | — | — | — | 1,011,948 | ||||||||||||||||||
Payments on long-term debt | — | (759,637 | ) | — | (214 | ) | — | (759,851 | ) | |||||||||||||||
Debt issuance costs | — | (2,302 | ) | — | — | — | (2,302 | ) | ||||||||||||||||
Other | — | — | — | — | — | — | ||||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (26,233 | ) | 250,009 | — | (214 | ) | — | 223,562 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | (33,669 | ) | (3,723 | ) | — | (4,889 | ) | (2,241 | ) | (44,522 | ) | |||||||||||||
Cash and Cash Equivalents, beginning of period | 135,703 | 3,723 | — | 6,380 | — | 145,806 | ||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 102,034 | $ | — | $ | — | $ | 1,491 | $ | (2,241 | ) | $ | 101,284 |
237
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Six Months Ended December 31, 2013 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 27,210 | $ | 37,107 | $ | 173,006 | $ | 51,188 | $ | (261,301 | ) | $ | 27,210 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | �� | |||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 197,060 | 1,756 | — | 198,816 | ||||||||||||||||||
Deferred income tax expense | — | 19,541 | — | (3,036 | ) | — | 16,505 | |||||||||||||||||
Change in fair value of derivative financial instruments | — | 46,655 | — | — | — | 46,655 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 14,751 | — | — | 14,751 | ||||||||||||||||||
Loss from equity method investees | (26,117 | ) | (169,089 | ) | — | 6,838 | 193,201 | 4,833 | ||||||||||||||||
Amortization and write-off of debt issuance costs and other | 1,463 | 3,071 | — | 21 | — | 4,555 | ||||||||||||||||||
Stock-based compensation | 3,971 | — | — | — | — | 3,971 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | — | 11,294 | 6,735 | (1,030 | ) | — | 16,999 | |||||||||||||||||
Prepaid expenses and other current assets | (364 | ) | 6,561 | (95 | ) | 117 | — | 6,219 | ||||||||||||||||
Settlement of asset retirement obligations | — | — | (34,038 | ) | — | — | (34,038 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | (20,158 | ) | (266,929 | ) | 60,740 | 112,000 | 69,571 | (44,776 | ) | |||||||||||||||
Net Cash Provided by (Used in) Operating Activities | (13,995 | ) | (311,789 | ) | 418,159 | 167,854 | 1,471 | 261,700 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (12,564 | ) | — | — | (12,564 | ) | ||||||||||||||||
Capital expenditures | — | 19,618 | (406,597 | ) | (1,248 | ) | — | (388,227 | ) | |||||||||||||||
Change in equity method investments | — | — | — | (11,694 | ) | — | (11,694 | ) | ||||||||||||||||
Transfers to restricted cash | — | — | (746 | ) | — | — | (746 | ) | ||||||||||||||||
Proceeds from the sale of properties | — | — | 1,748 | — | — | 1,748 | ||||||||||||||||||
Other | — | — | — | (72 | ) | — | (72 | ) | ||||||||||||||||
Net Cash Used in (Provided by) Investing Activities | — | 19,618 | (418,159 | ) | (13,014 | ) | — | (411,555 | ) | |||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 3,405 | — | — | — | — | 3,405 | ||||||||||||||||||
Proceeds from convertible debt allocated to additional paid-in capital | 63,432 | — | — | — | — | 63,432 | ||||||||||||||||||
Repurchase of company common stock | — | — | — | (153,491 | ) | — | (153,491 | ) | ||||||||||||||||
Dividends to shareholders – common | (17,798 | ) | — | — | — | — | (17,798 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (5,745 | ) | — | — | — | — | (5,745 | ) | ||||||||||||||||
Proceeds from long-term debt | 336,568 | 1,428,117 | — | — | — | 1,764,685 | ||||||||||||||||||
Payments on long-term debt | — | (1,127,673 | ) | — | (206 | ) | — | (1,127,879 | ) | |||||||||||||||
Debt issuance costs | (9,166 | ) | (9,757 | ) | — | — | — | (18,923 | ) | |||||||||||||||
Other | — | — | — | (3 | ) | — | (3 | ) | ||||||||||||||||
Net Cash Provided by (Used in) Financing Activities | 370,696 | 290,687 | — | (153,700 | ) | — | 507,683 | |||||||||||||||||
Net Decrease in Cash and Cash Equivalents | 356,701 | (1,484 | ) | — | 1,140 | 1,471 | 357,828 | |||||||||||||||||
Cash and Cash Equivalents, beginning of period | 1,334 | — | — | 137 | (1,471 | ) | — | |||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 358,035 | $ | (1,484 | ) | $ | — | $ | 1,277 | $ | — | $ | 357,828 |
238
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE SIX MONTHS ENDED DECEMBER 31, 2014
(Unaudited)
Note 22 — Subsequent Events
On January 27, 2015 the Board of Directors declared a dividend of $.01 per common share payable on March 13, 2015 to holders of record on February 27, 2015.
During January 2015, we monetized our existing calendar 2015 ICE Brent three-way collars and Argus-LLS put spreads for total net proceeds of approximately $73.1 million;, further, we repositioned our calendar 2015 hedging portfolio by entering into Argus-LLS three-way collars, and we entered into NYMEX WTI collars to hedge a portion of our calendar 2016 production at the current commodity prices.
239
Restated Quarterly Financial Statements for the Three and Nine Months Ended March 31, 2015
ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS
(In thousands, except share information)
(Unaudited)
March 31, 2015 (Restated) | June 30, 2014 (Restated) | |||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 602,024 | $ | 145,806 | ||||
Accounts receivable | ||||||||
Oil and natural gas sales | 83,919 | 167,075 | ||||||
Joint interest billings | 16,176 | 12,898 | ||||||
Other | 25,244 | 5,438 | ||||||
Prepaid expenses and other current assets | 39,608 | 72,530 | ||||||
Deferred income taxes | 16,959 | 52,587 | ||||||
Derivative financial instruments | 52,822 | 1,425 | ||||||
Total Current Assets | 836,752 | 457,759 | ||||||
Property and Equipment | ||||||||
Oil and natural gas properties, net – full cost method of accounting, including $680.0 million and $1,165.7 million of unevaluated properties not being amortized at March 31, 2015 and June 30, 2014, respectively | 5,851,833 | 6,427,263 | ||||||
Other property and equipment, net | 22,759 | 19,760 | ||||||
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 5,874,592 | 6,447,023 | ||||||
Other Assets | ||||||||
Goodwill | — | 329,293 | ||||||
Derivative financial instruments | 9,767 | 3,035 | ||||||
Equity investments | 25,050 | 40,643 | ||||||
Restricted Cash | 6,024 | 6,350 | ||||||
Other assets and debt issuance costs, net of accumulated amortization | 83,158 | 57,394 | ||||||
Total Other Assets | 123,999 | 436,715 | ||||||
Total Assets | $ | 6,835,343 | $ | 7,341,497 | ||||
LIABILITIES | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 192,472 | $ | 417,776 | ||||
Accrued liabilities | 117,574 | 133,526 | ||||||
Notes payable | 4,949 | 21,967 | ||||||
Asset retirement obligations | 68,392 | 79,649 | ||||||
Derivative financial instruments | — | 31,957 | ||||||
Current maturities of long-term debt | 17,282 | 15,020 | ||||||
Total Current Liabilities | 400,669 | 699,895 | ||||||
Long-term debt, less current maturities | 4,595,770 | 3,744,624 | ||||||
Deferred income taxes | 397,543 | 666,969 | ||||||
Asset retirement obligations | 469,033 | 480,185 | ||||||
Derivative financial instruments | 71 | 4,306 | ||||||
Other liabilities | 8,168 | 10,958 | ||||||
Total Liabilities | 5,871,254 | 5,606,937 |
See accompanying Notes to Consolidated Financial Statements
240
ENERGY XXI LTD
CONSOLIDATED BALANCE SHEETS – (continued)
(In thousands, except share information)
(Unaudited)
March 31, 2015 (Restated) | June 30, 2014 (Restated) | |||||||
Commitments and Contingencies (Note 17) | ||||||||
Stockholders’ Equity | ||||||||
Preferred stock, $0.001 par value, 7,500,000 shares authorized at March 31, 2015 and June 30, 2014 | ||||||||
7.25% Convertible perpetual preferred stock, 3,000 and 8,000 shares issued and outstanding at March 31, 2015 and June 30, 2014, respectively | $ | — | $ | — | ||||
5.625% Convertible perpetual preferred stock, 812,759 and 812,760 shares issued and outstanding at March 31, 2015 and June 30, 2014, respectively | 1 | 1 | ||||||
Common stock, $0.005 par value, 200,000,000 shares authorized and 94,428,557 and 93,719,570 shares issued and outstanding at March 31, 2015 and June 30, 2014, respectively | 471 | 468 | ||||||
Additional paid-in capital | 1,842,919 | 1,837,462 | ||||||
Accumulated deficit | (879,302 | ) | (103,371 | ) | ||||
Total Stockholders’ Equity | 964,089 | 1,734,560 | ||||||
Total Liabilities and Stockholders’ Equity | $ | 6,835,343 | $ | 7,341,497 |
See accompanying Notes to Consolidated Financial Statements
241
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share information)
(Unaudited)
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
2015 (Restated) | 2014 (Restated) | 2015 (Restated) | 2014 (Restated) | |||||||||||||
Revenues | ||||||||||||||||
Crude oil sales | $ | 177,605 | $ | 254,641 | $ | 827,468 | $ | 809,234 | ||||||||
Natural gas sales | 27,012 | 37,562 | 93,374 | 101,284 | ||||||||||||
Gain (loss) on derivative financial instruments | 16,963 | (7,349 | ) | 265,150 | (58,703 | ) | ||||||||||
Total Revenues | 221,580 | 284,854 | 1,185,992 | 851,815 | ||||||||||||
Costs and Expenses | ||||||||||||||||
Lease operating | 108,110 | 83,624 | 370,061 | 263,176 | ||||||||||||
Production taxes | 1,537 | 1,090 | 6,893 | 3,677 | ||||||||||||
Gathering and transportation | 3,726 | 5,700 | 17,685 | 17,023 | ||||||||||||
Depreciation, depletion and amortization | 187,947 | 97,708 | 522,242 | 296,524 | ||||||||||||
Accretion of asset retirement obligations | 12,106 | 6,066 | 37,723 | 20,817 | ||||||||||||
Impairment of oil and natural gas properties | 569,616 | — | 569,616 | — | ||||||||||||
Goodwill impairment | — | — | 329,293 | — | ||||||||||||
General and administrative expense | 37,121 | 24,208 | 91,290 | 65,578 | ||||||||||||
Total Costs and Expenses | 920,163 | 218,396 | 1,944,803 | 666,795 | ||||||||||||
Operating Income (Loss) | (698,583 | ) | 66,458 | (758,811 | ) | 185,020 | ||||||||||
Other Income (Expense) | ||||||||||||||||
Loss from equity method investees | (2,635 | ) | (1,097 | ) | (2,951 | ) | (5,930 | ) | ||||||||
Other income – net | 1,231 | 867 | 3,173 | 2,302 | ||||||||||||
Interest expense | (85,039 | ) | (42,700 | ) | (218,203 | ) | (111,026 | ) | ||||||||
Total Other Expense | (86,443 | ) | (42,930 | ) | (217,981 | ) | (114,654 | ) | ||||||||
Income (Loss) Before Income Taxes | (785,026 | ) | 23,528 | (976,792 | ) | 70,366 | ||||||||||
Income Tax Expense (Benefit) | (289,965 | ) | 17,210 | (232,958 | ) | 36,838 | ||||||||||
Net Income (Loss) | (495,061 | ) | 6,318 | (743,834 | ) | 33,528 | ||||||||||
Preferred Stock Dividends | 2,862 | 2,872 | 8,605 | 8,617 | ||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (497,923 | ) | $ | 3,446 | $ | (752,439 | ) | $ | 24,911 | ||||||
Earnings (Loss) per Share | ||||||||||||||||
Basic | $ | (5.27 | ) | $ | 0.05 | $ | (8.00 | ) | $ | 0.34 | ||||||
Diluted | $ | (5.27 | ) | $ | 0.05 | $ | (8.00 | ) | $ | 0.34 | ||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||
Basic | 94,408 | 70,437 | 94,076 | 73,415 | ||||||||||||
Diluted | 94,408 | 70,502 | 94,076 | 73,493 |
See accompanying Notes to Consolidated Financial Statements
242
ENERGY XXI LTD
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
Nine Months Ended March 31, | ||||||||
2015 (Restated) | 2014 (Restated) | |||||||
Cash Flows From Operating Activities | ||||||||
Net income (loss) | $ | (743,834 | ) | $ | 33,528 | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation, depletion and amortization | 522,242 | 296,524 | ||||||
Impairment of oil and natural gas properties | 569,616 | — | ||||||
Goodwill impairment | 329,293 | — | ||||||
Deferred income tax expense (benefit) | (233,798 | ) | 33,475 | |||||
Change in fair value of derivative financial instruments | (85,086 | ) | 46,915 | |||||
Accretion of asset retirement obligations | 37,723 | 20,817 | ||||||
Loss from equity method investees | 2,951 | 5,930 | ||||||
Amortization and write-off of debt issuance costs and other | 17,942 | 9,715 | ||||||
Stock-based compensation | 3,271 | 5,292 | ||||||
Changes in operating assets and liabilities | ||||||||
Accounts receivable | 62,163 | 20,551 | ||||||
Prepaid expenses and other assets | 32,938 | 28,130 | ||||||
Settlement of asset retirement obligations | (77,235 | ) | (46,269 | ) | ||||
Accounts payable and accrued liabilities | (277,854 | ) | (8,692 | ) | ||||
Net Cash Provided by Operating Activities | 160,332 | 445,916 | ||||||
Cash Flows from Investing Activities | ||||||||
Acquisitions | (301 | ) | (35,082 | ) | ||||
Capital expenditures | (512,302 | ) | (574,824 | ) | ||||
Insurance payments received | 2,669 | — | ||||||
Change in equity method investments | 12,642 | (11,694 | ) | |||||
Transfer from (to) restricted cash | 325 | (325 | ) | |||||
Proceeds from the sale of properties | 7,093 | 1,748 | ||||||
Other | 185 | 624 | ||||||
Net Cash Used in Investing Activities | (489,689 | ) | (619,553 | ) | ||||
Cash Flows from Financing Activities | ||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,187 | 3,844 | ||||||
Proceeds from convertible debt allocated to additional paid-in capital | — | 63,432 | ||||||
Repurchase of company common stock | — | (184,263 | ) | |||||
Dividends to shareholders – common | (23,492 | ) | (26,238 | ) | ||||
Dividends to shareholders – preferred | (8,605 | ) | (8,617 | ) | ||||
Proceeds from long-term debt | 2,586,572 | 2,039,759 | ||||||
Payments on long-term debt | (1,729,355 | ) | (1,391,379 | ) | ||||
Debt issuance costs | (41,732 | ) | (19,199 | ) | ||||
Net Cash Provided by Financing Activities | 785,575 | 477,339 | ||||||
Net Increase in Cash and Cash Equivalents | 456,218 | 303,702 | ||||||
Cash and Cash Equivalents, beginning of period | 145,806 | — | ||||||
Cash and Cash Equivalents, end of period | $ | 602,024 | $ | 303,702 |
See accompanying Notes to Consolidated Financial Statements
243
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 1 — Organization and Summary of Significant Accounting Policies
Nature of Operations. Energy XXI Ltd was incorporated in Bermuda on July 25, 2005. References in this report to “us,” “we,” “our,” “the Company,” or “Energy XXI” are to Energy XXI Ltd and its wholly-owned subsidiaries. With our principal operating subsidiary 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 in the Gulf of Mexico Shelf (“GoM Shelf”). We are listed on the NASDAQ Global Select Market (“NASDAQ”) under the symbol “EXXI”.
Principles of Consolidation and Reporting. The accompanying consolidated financial statements include the accounts of Energy XXI and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All significant intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. We use the equity method of accounting for investments in entities that we do not control, but over which we exert significant influence.
Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in this Form 10-K.
Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in accounting for acquisitions; carrying amounts of property, plant and equipment; goodwill; asset retirement obligations; deferred income taxes; and valuation of derivative financial instruments, among others. Accordingly, our accounting estimates require exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material.
Note 2 — Recent Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09,Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. ASU No. 2014-09 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method that will be adopted.
244
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 2 — Recent Accounting Pronouncements – (continued)
In August 2014, the FASB issued Accounting Standards Update No. 2014-15,Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU 2014-15”). ASU 2014-15 requires management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. The standard is effective for annual periods ending after December 15, 2016, and interim periods within annual periods beginning after December 15, 2016, with early adoption permitted. We are currently evaluating the provisions of ASU 2014-15 and assessing the impact, if any, it may have on our consolidated financial statements.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03,Interest — Imputation of Interest (Subtopic 835-30) (“ASU 2015-03”). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability. The ASU is effective for public entities for annual periods beginning after December 15, 2015, and interim periods within those annual reporting periods. Early adoption is permitted for financial statements that have not been previously issued. The guidance will be applied on a retrospective basis. We are currently evaluating the provisions of ASU 2015-03 and assessing the impact it may have on our consolidated financial position, results of operations or cash flows.
Note 3 — Acquisitions and Dispositions
Black Elk Interest
On December 20, 2013, we acquired certain offshore Louisiana interests in the West Delta 30 field (“West Delta 30 Interests”) from Black Elk Energy Offshore Operations, LLC for total cash consideration of $10.4 million. This acquisition was effective as of October 1, 2013, and we are currently the operator of these properties.
Revenues and expenses related to the West Delta 30 Interests are included in our consolidated statements of operations from December 20, 2013. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on December 20, 2013 (in thousands):
Oil and natural gas properties – evaluated | $ | 15,821 | ||
Oil and natural gas properties – unevaluated | 6,586 | |||
Asset retirement obligations | (10,503 | ) | ||
Net working capital* | (1,500 | ) | ||
Cash paid | $ | 10,404 |
* | Net working capital includes payables. |
Walter Oil & Gas Corporation Oil and Gas Properties Interests
On March 7, 2014, we closed on the acquisition of certain interests in the South Timbalier 54 Block (“South Timbalier 54 Interests”) from Walter Oil & Gas Corporation for total cash consideration of approximately $22.8 million. This acquisition was effective as of January 1, 2014, and we are currently the operator of these properties.
245
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
Revenues and expenses related to the South Timbalier 54 Interests are included in our consolidated statements of operations from March 7, 2014. The following table presents the final purchase price allocation to the assets acquired and liabilities assumed, based on their fair values on March 7, 2014 (in thousands):
Oil and natural gas properties – evaluated | $ | 23,497 | ||
Asset retirement obligations | (705 | ) | ||
Cash paid | $ | 22,792 |
We have accounted for our acquisitions using the acquisition method of accounting, and therefore, we have estimated the fair value of the assets acquired and liabilities assumed as of their respective acquisition dates. In the estimation of fair values of evaluated and unevaluated oil and natural gas properties and asset retirement obligations for the above acquisitions, management used valuation techniques that convert future cash flows to single discounted amounts. Inputs to the valuation of oil and gas properties include estimates of: (1) oil and gas reserves; (2) future operating and development costs; (3) future oil and natural gas prices; and (4) a discount factor used to calculate the discounted cash flow amount. Inputs into the valuation of the asset retirement obligations include estimates of: (1) plugging and abandonment costs per well and related facilities; (2) remaining life per well and facilities; (3) an inflation factor; and (4) a credit adjusted risk-free interest rate. Fair value is based on subjective estimates and assumptions, which are inherently subject to significant uncertainties which are beyond our control. These assumptions represent Level 3 inputs, as further discussed in Note 18 — Fair Value of Financial Instruments.
EPL Oil & Gas, Inc. (“EPL”)
We acquired EPL on June 3, 2014 (the “EPL Acquisition”). The acquisition was accounted for under the acquisition method, with Energy XXI as the acquirer. EPL is now a wholly owned subsidiary of Energy XXI Gulf Coast, Inc. (“EGC”). Subsequent to the merger, we elected to change EPL’s fiscal year end to June 30 to coincide with our fiscal year end.
In connection with the EPL Acquisition, each EPL stockholder had the right to elect to receive, for each share of EPL common stock held by that stockholder, $39.00 in cash (“Cash Election”), or 1.669 shares of Energy XXI common stock (“Stock Election”) or a combination of $25.35 in cash and 0.584 of a share of Energy XXI common stock (“Mixed Election” and together with the Cash Election and the Stock Election, the “Merger Consideration”), subject to proration with respect to the Stock Election and the Cash Election so that approximately 65% of the aggregate Merger Consideration was paid in cash and approximately 35% was paid in Energy XXI common stock. Accordingly, EPL stockholders making a timely Cash Election received $25.92 in cash and 0.5595 of a share of Energy XXI common stock for each EPL common share. Under the merger agreement, EPL stockholders who did not make an election prior to the May 30th deadline were treated as having made a Mixed Election. In addition to the outstanding EPL shares, each outstanding stock option to purchase shares of EPL common stock was deemed exercised pursuant to a cashless exercise and was converted into the right to receive the cash portion of the Merger Consideration pursuant to the Cash Election, without being subject to proration. As a result, in accordance with the merger agreement, 836,311 net exercise shares were converted into $39.00 per share in cash, without proration. Based on the final results of the Merger Consideration elections and as set forth in the merger agreement, we issued 23.3 million shares of Energy XXI common stock and paid approximately $1,012 million in cash.
246
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
The following table summarizes the preliminary purchase price allocation for the EPL Acquisition as of June 3, 2014 (in thousands):
EPL Historical | Fair Value Adjustment | Total | ||||||||||
(Unaudited) | ||||||||||||
Current assets (excluding deferred income taxes) | $ | 301,592 | $ | 1,274 | $ | 302,866 | ||||||
Oil and natural gas properties(a) | ||||||||||||
Evaluated (Including net ARO assets) | 1,919,699 | 112,624 | 2,032,323 | |||||||||
Unevaluated | 41,896 | 859,886 | 901,782 | |||||||||
Other property and equipment | 7,787 | — | 7,787 | |||||||||
Other assets | 16,227 | (9,002 | ) | 7,225 | ||||||||
Current liabilities (excluding ARO) | (314,649 | ) | (2,058 | ) | (316,707 | ) | ||||||
ARO (current and long-term) | (260,161 | ) | (13,211 | ) | (273,372 | ) | ||||||
Debt (current and long-term) | (973,440 | ) | (52,967 | ) | (1,026,407 | ) | ||||||
Deferred income taxes(b) | (118,359 | ) | (340,645 | ) | (459,004 | ) | ||||||
Other long-term liabilities | (2,242 | ) | 797 | (1,445 | ) | |||||||
Total fair value, excluding goodwill | 618,350 | 556,698 | 1,175,048 | |||||||||
Goodwill(c),(d) | — | 329,293 | 329,293 | |||||||||
Less cash acquired | — | — | 206,075 | |||||||||
Total purchase price | $ | 618,350 | $ | 885,991 | $ | 1,298,266 |
(a) | EPL oil and gas properties were accounted for under the successful efforts method of accounting prior to the merger. After the merger, we are accounting for these oil and gas properties under the full cost method of accounting, which is consistent with our accounting policy. |
(b) | Deferred income taxes have been recognized based on the estimated fair value adjustments to net assets using a 37% tax rate, which reflected the 35% federal statutory rate and a 2% weighted-average of the applicable statutory state tax rates (net of federal benefit). |
(c) | See Note 4 — Goodwill within these quarterly consolidated financial statements for more information regarding goodwill impairment at December 31, 2014. |
(d) | On April 2, 2013, EPL sold certain shallow water GoM Shelf oil and natural gas interests located within the non-operated Bay Marchand field to Chevron U.S.A. Inc. (“Chevron”) with an effective date of January 1, 2013. In September 2014, we were informed by Chevron that the final settlement statement did not reflect a portion of the related production in the months of January 2013 and February 2013 totaling approximately $2.1 million. After review of relevant supporting documents, we agreed to reimburse Chevron approximately $2.1 million. This resulted in an increase in liabilities assumed in the EPL Acquisition and a corresponding increase in goodwill of approximately $2.1 million. Accordingly, the June 30, 2014 comparative information has been retrospectively adjusted to increase the value of goodwill. |
In accordance with the acquisition method of accounting, we have allocated the purchase price from our acquisition of EPL to the assets acquired and liabilities assumed based on their estimated fair values on the acquisition date. The fair value estimates were based on, but not limited to, quoted market prices, where available; expected future cash flows based on estimated reserve quantities; costs to produce and develop reserves; current replacement cost for similar capacity for certain fixed assets; market rate assumptions for contractual obligations; appropriate discount rates and growth rates; and crude oil and natural gas forward prices. The excess of the total consideration over the estimated fair value of the amounts initially assigned to the identifiable assets acquired and liabilities assumed was recorded as goodwill. Goodwill recorded in connection with the EPL Acquisition is not deductible for income tax purposes.
247
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
The final valuation of assets acquired and liabilities assumed is not complete and the net adjustments to those values may result in changes to goodwill and other carrying amounts initially assigned to the assets and liabilities based on the preliminary fair value analysis. The principal remaining items to be valued are tax assets and liabilities, and any related valuation allowances, which will be finalized in connection with the filing of related tax returns.
The fair value estimates of the oil and natural gas properties and the asset retirement obligations were based, in part, on significant inputs not observable in the market and thus represent Level 3 measurements. The fair value estimate of long-term debt was based on prices obtained from a readily available pricing source and thus represents a Level 2 measurement.
The EPL Acquisition resulted in goodwill primarily because the combined company resulted in a significantly increased enterprise value and this increased scale provided us with opportunities to increase our equity market liquidity, lower insurance costs, achieve operating efficiencies by utilizing EPL’s existing infrastructure and lower costs through optimization of offshore transport vehicles and consolidation of shore bases, lowering general and administrative expenditures by consolidating corporate support functions and utilizing complementary strengths and expertise of the technical staff of the two companies to timely identify and drill prospects. We can utilize the latest drilling and seismic acquisition technologies, namely dump-floods, horizontal drilling, WAZ and Full Azimuth Nodal (“FAN”) seismic technologies licensed by EPL, which enhance production and assist in identifying deep-seated structures in the shallow waters over a significantly broader asset portfolio concentrated in the GoM Shelf. In addition, goodwill also resulted from the requirement to recognize deferred taxes on the difference between the fair value and the tax basis of the acquired assets. During the quarter ended December 31, 2014, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014. See Note 4 — Goodwill within these quarterly consolidated financial statements for more information regarding the impairment of goodwill at December 31, 2014.
In the year ended June 30, 2014, costs associated with the EPL Acquisition totaled approximately $13.6 million and were expensed as incurred. For the quarter ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $83.2 million and net loss of $54.0 million. For the nine months ended March 31, 2015, our Consolidated Statement of Operations includes EPL’s operating revenues of $433.0 million and net loss of $355.7 million.
The following supplemental unaudited pro forma financial information has been prepared to reflect the EPL Acquisition as if the merger had occurred on July 1, 2012. The supplemental unaudited pro forma financial information is based on the historical consolidated statements of income of Energy XXI and EPL for the three and nine months ended March 31, 2014 (in thousands, except per share amounts).
Three Months Ended March 31, 2014 | Nine Months Ended March 31, 2014 | |||||||
Revenues | $ | 452,764 | $ | 1,364,845 | ||||
Net income (loss) | 15,561 | (3,081 | ) | |||||
Net income (loss) available to Energy XXI common stockholders | 12,689 | (11,698 | ) | |||||
Net income per share available to Energy XXI common stockholders: | ||||||||
Basic | $ | 0.14 | $ | (0.12 | ) | |||
Diluted | $ | 0.14 | $ | (0.12 | ) |
248
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 3 — Acquisitions and Dispositions – (continued)
The above supplemental unaudited pro forma financial information has been prepared for illustrative purposes only and is not intended to be indicative of the results of operations that actually would have occurred had the acquisition occurred on July 1, 2012, nor is such information indicative of any expected results of operations in future periods. The most significant pro forma adjustments for the three and nine months ended March 31, 2014, were the following:
a. | Exclude $5.0 million and $22.0 million, respectively, of EPL’s exploration costs, impairment expense and gain on sales of assets accounted for under the successful efforts method of accounting to correspond with EXXI’s full cost method of accounting. |
b. | Increase DD&A expense by $13.7 million and $62.9 million, respectively, for the EPL properties to correspond with EXXI’s full cost method of accounting. |
c. | Increase interest expense by $12.8 million and $39.0 million, respectively, to reflect interest on the $650 million 6.875% unsecured senior notes due 2024 (the “6.875% Senior Notes”) and on additional borrowings under EXXI’s revolving credit facility. Decrease interest expense $3.4 million and $10.0 million, respectively, to reflect non-cash premium amortization due to the adjustment to fair value associated with the $510 million 8.25% senior notes due 2018 (the “8.25% Senior Notes”) assumed in the EPL Acquisition. |
Sales of Oil and Natural Gas properties interests
On April 1, 2014, Energy XXI GOM, LLC (“EXXI GOM”), our wholly owned indirect subsidiary closed on the sale of its interests in Eugene Island 330 and South Marsh Island 128 fields to M21K, LLC, which is a wholly owned subsidiary of our equity method investee, Energy XXI M21K, LLC (“EXXI M21K”), for cash consideration of approximately $122.9 million. Revenues and expenses related to these two fields were included in our results of operations through March 31, 2014. The proceeds were recorded as a reduction to our oil and natural gas properties with no gain or loss being recognized. The net reduction to the full cost pool related to this sale was $124.4 million.
Note 4 — Goodwill
ASC 350,Intangibles — Goodwill and Other (ASC 350), requires that intangible assets with indefinite lives, including goodwill, be evaluated for impairment on an annual basis or more frequently if events occur or circumstances change that could potentially result in impairment. Our annual goodwill impairment test is performed as of the last day of the fourth quarter each fiscal year.
Impairment testing for goodwill is done at the reporting unit level. We have only one reporting unit, which includes all of our oil and natural gas properties. Accordingly, all of our goodwill, as well as all of our other assets and liabilities, are included in our single reporting unit.
At December 31, 2014, we conducted a qualitative goodwill impairment assessment by examining relevant events and circumstances that could have a negative impact on our goodwill, such as macroeconomic conditions, industry and market conditions, cost factors that have a negative effect on earnings and cash flows, overall financial performance, dispositions and acquisitions, and any other relevant events or circumstances. After assessing the relevant events and circumstances for the qualitative impairment assessment, we determined that performing a quantitative goodwill impairment test was necessary. In the first step of the goodwill impairment test, we determined that the fair value of our reporting unit was less than its carrying amount, including goodwill, primarily due to price deterioration in forward pricing curves for oil and natural gas and an increase in our weighted average cost of capital, both factors which adversely impacted the fair value of our estimated reserves. Therefore, we performed the second step of the goodwill impairment test,
249
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 4 — Goodwill – (continued)
which led us to conclude that there would be no remaining implied fair value attributable to goodwill. As a result, we recorded a goodwill impairment charge of $329.3 million to reduce the carrying value of goodwill to zero at December 31, 2014.
In estimating the fair value of our reporting unit and our estimated reserves, we used an income approach which estimated fair value primarily based on the anticipated cash flows associated with our estimated reserves, discounted using a weighted average cost of capital. The estimation of the fair value of our reporting unit and our estimated reserves includes the use of significant inputs not observable in the market, such as estimates of reserves quantities, the weighted average cost of capital (discount rate), future pricing and future capital and operating costs. The use of these unobservable inputs results in the fair value estimate being classified as a Level 3 measurement. Although we believe the assumptions and estimates used in the fair value calculation of our reporting unit were reasonable and appropriate, different assumptions and estimates could materially impact the analysis and resulting conclusions.
Note 5 — Property and Equipment
Property and equipment consists of the following (in thousands):
March 31, 2015 (Restated) | June 30, 2014 (Restated) | |||||||
Oil and gas properties | ||||||||
Proved properties | $ | 9,246,556 | $ | 8,247,352 | ||||
Less: accumulated depreciation, depletion, amortization and impairment | 4,074,772 | 2,985,790 | ||||||
Proved properties, net | 5,171,784 | 5,261,562 | ||||||
Unevaluated properties | 680,049 | 1,165,701 | ||||||
Oil and gas properties, net | 5,851,833 | 6,427,263 | ||||||
Other property and equipment | 45,809 | 39,272 | ||||||
Less: accumulated depreciation | 23,050 | 19,512 | ||||||
Other property and equipment, net | 22,759 | 19,760 | ||||||
Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment | $ | 5,874,592 | $ | 6,447,023 |
At March 31, 2015, the Company’s investment in unevaluated properties primarily relates to the fair value of unproved oil and gas properties acquired in oil and gas property acquisitions (primarily the EPL Acquisition). Costs associated with unevaluated properties are transferred to evaluated properties upon the earlier of 1) a determination as to whether there are any proved reserves related to the properties, or 2) amortization over a period of time of not more than four years.
At June 30, 2014, our unevaluated properties included exploratory wells in progress of $185.3 million in costs related to our participation in several prospects in the ultra-deep shelf and onshore area in the Gulf of Mexico with Freeport-McMoRan, Inc. who operates the properties. Based on information from Freeport-McMoRan and our internal assessment of ongoing exploratory wells, we concluded the following: 1) the Lomond North project resulted in a successful production test with commercial production commencing in the quarter ending March 31, 2015; 2) the Davy Jones project to be non-commercial in the Tuscaloosa and Wilcox Sands area, and it was temporarily plugged and abandoned; 3) we presently do not intend to participate in completion activities related to the Davy Jones project; and 4) the lease related to the
250
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 5 — Property and Equipment – (continued)
Blackbeard East project expired. Accordingly, we transferred $208.2 million of accumulated exploratory costs associated with these projects included in unevaluated properties to evaluated properties during the nine months ended March 31, 2015.
Under the full cost method of accounting at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unproved properties and excluding cash flows related to estimated abandonment costs) to the net full cost pool of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the value of the discounted cash flows. At March 31, 2015, our ceiling test computation resulted in an impairment of our oil and natural gas properties of $569.6 million. If the current low commodity price environment or downward trend in oil prices continues, there is a reasonable likelihood that we could incur further impairment to our full cost pool in fiscal 2015 and 2016 based on the average oil and natural gas price calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the previous 12-month period under the SEC pricing methodology.
Note 6 — Equity Method Investments
Energy XXI M21K
We own a 20% interest in EXXI M21K which engages in the acquisition, exploration, development and operation of oil and natural gas properties offshore in the Gulf of Mexico, through its wholly owned subsidiary, M21K, LLC (“M21K”). EGC, an indirect wholly owned subsidiary of Energy XXI receives a management fee from M21K for providing administrative assistance in carrying out its operations. See Note 15 — Related Party Transactions within these quarterly consolidated financial statements.
Since its inception in February 2012, M21K has completed three acquisitions for aggregate cash consideration of approximately $284.1 million. In July 2012, it acquired oil and gas interests from EP Energy E&P Company, L.P. for approximately $80.4 million. In August 2013, it acquired oil and gas interests from LLOG Exploration Offshore, L.L.C. for approximately $80.8 million. In April 2014, it acquired oil and gas interests from EXXI GOM for approximately $122.9 million. We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K related to these acquisitions.
EXXI M21K is a guarantor of a $100 million first lien credit facility agreement entered into by M21K, under which $31.0 million in loans and $1.2 million in letters of credit were outstanding as of March 31, 2015. M21K is currently in default due to a breach of certain covenants under this agreement and is currently in negotiations with its bank group to amend the credit facility.
The provisions of the M21K Limited Liability Company Agreement (“LLC Agreement”) provide that M21K can make acquisitions subject to the commitment of its partners. While it is envisioned that M21K will eventually be sold to a third party to monetize returns from the investments, the M21K LLC Agreement does provide for a put and a call that can occur starting July 19, 2016, subject to an earlier option if there is a change of control of Energy XXI. Pursuant to the exercise of the put option, we may be required to pay the fair value calculated on the basis of the current proved reserves as determined by a duly appointed reserve engineering firm utilizing then prevailing forward pricing and cost curves, however we will have no obligation to purchase any partnership interests if both: (i) the put value exceeds the lesser of: (a) $100 million or (b) 20% of the aggregate capital contributions; and (ii) the put right was not triggered by the occurrence of a change of control.
251
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 6 — Equity Method Investments – (continued)
As of March 31, 2015, our investment in EXXI M21K was approximately $25.1 million. We recorded an equity loss of $2.6 million and $3.0 million for the three and nine months ended March 31, 2015, respectively. We recorded an equity loss of $1.1 million and $4.7 million for the three and nine months ended March 31, 2014, respectively.
Note 7 — Long-Term Debt
Long-term debt consists of the following (in thousands):
March 31, 2015 | June 30, 2014 | |||||||
Revolving Credit Facility | $ | 150,000 | $ | 689,000 | ||||
11.0% Senior Secured Second Lien Notes due 2020 | 1,450,000 | — | ||||||
8.25% Senior Notes due 2018 | 510,000 | 510,000 | ||||||
6.875% Senior Notes due 2024 | 650,000 | 650,000 | ||||||
3.0% Senior Convertible Notes due 2018 | 400,000 | 400,000 | ||||||
7.5% Senior Notes due 2021 | 500,000 | 500,000 | ||||||
7.75% Senior Notes due 2019 | 250,000 | 250,000 | ||||||
9.25% Senior Notes due 2017 | 750,000 | 750,000 | ||||||
4.14% Promissory Note due 2017 | 4,452 | 4,774 | ||||||
Debt premium, 8.25% Senior Notes due 2018(1) | 32,855 | 40,566 | ||||||
Original issue discount, 11.0% Notes due 2020 | (53,043 | ) | — | |||||
Original issue discount, 3.0% Senior Convertible Notes due 2018 | (48,658 | ) | (57,014 | ) | ||||
Derivative instruments premium financing | 16,461 | 21,000 | ||||||
Capital lease obligations | 985 | 1,318 | ||||||
Total debt | 4,613,052 | 3,759,644 | ||||||
Less current maturities | 17,282 | 15,020 | ||||||
Total long-term debt | $ | 4,595,770 | $ | 3,744,624 |
(1) | Represents unamortized premium on the 8.25% Senior Notes assumed in the EPL Acquisition. |
Maturities of long-term debt as of March 31, 2015 are as follows (in thousands):
Twelve Months Ended March 31, | ||||
2016 | $ | 17,282 | ||
2017 | 752 | |||
2018 | 753,864 | |||
2019 | 1,060,000 | |||
2020 | 1,700,000 | |||
Thereafter | 1,150,000 | |||
4,681,898 | ||||
Less: Net original issue discount & debt premium | (68,846 | ) | ||
Total debt | $ | 4,613,052 |
252
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
Revolving Credit Facility
On March 3, 2015, EGC and EPL entered into the Tenth Amendment (the “Tenth Amendment”) to their second amended and restated first lien credit agreement (the “First Lien Credit Agreement” or “Revolving Credit Facility”) in connection with the issuance of $1.45 billion of senior secured second lien notes as described below under “11.0% Senior Secured Second Lien Notes Due 2020.” Under the Tenth Amendment, the following changes, among others, to the First Lien Credit Agreement became effective:
• | reduction of the maximum facility amount to $500 million and establishment of the borrowing base at such $500 million, of which such amount $150 million is the borrowing base for EPL under the sub-facility established for EPL under the First Lien Credit Agreement; |
• | addition of provisions to permit EGC to make a loan to EPL in the amount of $325 million using proceeds from the incurrence of additional permitted second lien or third lien indebtedness of EGC and for EPL and its subsidiaries to secure such loan by providing liens on substantially all of their assets that are second in priority to the liens of the lenders under the First Lien Credit Agreement pursuant to the terms of an intercreditor agreement and restricting the transfer of EGC’s rights in respect of such loan or making any prepayment or otherwise making modifications of the terms of such arrangements; |
• | change in the definition of the stated maturity date of the First Lien Credit Agreement so that it accelerates from April 9, 2018 (the scheduled date of maturity) to a date 210 days prior to the date of maturity of EGC’s outstanding 9.25% unsecured notes due December 2017 (the “9.25% Senior Notes”) if such notes are not prepaid, redeemed or refinanced prior to such prior date, or to a date 210 days prior to the date of maturity of EPL’s outstanding 8.25% Senior Notes due February 2018 if such notes are not prepaid, redeemed or refinanced prior to such prior date, or otherwise to a date that is 180 days prior to the date of maturity of any other permitted second lien or permitted third lien indebtedness or certain permitted unsecured indebtedness or any refinancings of such indebtedness if such indebtedness would come due prior to April 9, 2018; |
• | elimination, addition, or modification of certain financial covenants; |
• | setting the applicable commitment fee under the First Lien Credit Agreement at 0.50% and providing that outstanding amounts drawn under the First Lien Credit Agreement bear interest at either the applicable London Interbank Offered Rate (“LIBOR”), plus applicable margins ranging from 2.75% to 3.75% or an alternate base rate based on the federal funds effective rate plus applicable margins ranging from 1.75% to 2.75%; |
• | increase of the threshold requirement for oil and gas properties required to be secured by mortgages to 90% of the value of EGC and its subsidiaries’ (other than EPL and its subsidiaries until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) proved reserves and proved developed producing reserves, but allowing the threshold for such properties of EPL and its subsidiaries (until they become guarantors of the EGC indebtedness under the First Lien Credit Agreement) to remain at 85%; |
• | addition of certain further restrictions on the prepayment and repayment of outstanding note indebtedness of EGC and its subsidiaries, including the prohibition on using proceeds from credit extensions under the First Lien Credit Agreement for any such prepayment or repayment and the requirement that EGC have net liquidity at the time thereof of at least $250 million; |
253
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
• | modification to the restricted payment covenant to substantially limit the ability of EGC to make distributions and dividends to parent entities, provided that a distribution of the Grand Isle gathering system (the “Grand Isle Assets”) and related equipment and other assets is permitted; |
• | qualification on the ability of EGC and its subsidiaries to refinance outstanding indebtedness by requiring that EGC have pro forma net liquidity of $250 million at the time of such refinancing; and |
• | modification of the asset disposition covenant to require lender consent for any such disposition that would have the effect of reducing the borrowing base by more than $5 million in the aggregate; provided, however, that such provision is expressly deemed not to be applicable to certain sales relating to the Grand Isle Assets that are the subject of current marketing efforts of EGC, as long as EGC and its subsidiaries meet certain obligations, such as, among others, maintaining the proceeds from such sales in accounts that are subject to the liens of the lenders. |
During the quarter ended March 31, 2015, as a result of the reduction in the borrowing capacity under our Revolving Credit Facility pursuant to the Tenth Amendment, we wrote off $8.9 million of previously capitalized debt issue costs.
The First Lien Credit Agreement, as amended, requires EGC and EPL to maintain certain financial covenants separately for so long as the 8.25% Senior Notes remain outstanding. EGC is subject to the following financial covenant on a consolidated basis: a minimum current ratio of no less than 1.0 to 1.0. In addition, EGC is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0. In addition, EPL is subject to the following financial covenants on a stand-alone basis: (a) a consolidated maximum first lien leverage ratio of 1.25 to 1.0 and (b) a consolidated maximum secured leverage ratio of no more than 3.75 to 1.0. If the EPL Notes are no longer outstanding and certain other conditions are met, EGC and EPL will be subject to the following financial covenants on a consolidated basis: (a) a consolidated maximum net first lien leverage ratio of 1.25 to 1.0, (b) a consolidated maximum net secured leverage ratio of no more than 3.75 to 1.0, provided that if the 8.25% Senior Notes are refinanced with new secured debt, the liens of which are junior in priority to the Revolving Credit Facility indebtedness, then the maximum ratio permitted would be 4.25 to 1.0, and (c) a minimum current ratio of no less than 1.0 to 1.0.
Under the First Lien Credit Agreement, as amended under the Tenth Amendment, EGC’s rights to make distributions to its shareholders (including ultimately to Energy XXI) are substantially reduced. Generally, under the Tenth Amendment, EGC is only permitted to make such distributions for income tax liabilities arising for such other entities that relate to the income attributable to EGC and its subsidiaries, general and administrative expenses not to exceed $2 million in any fiscal year and for payment of insurance premiums in regards to affiliated party insurance agreements.
As of March 31, 2015, EGC was in compliance with all covenants and had $150.0 million in borrowings and $226.0 million in letters of credit issued under the First Lien Credit Agreement.
11.0% Senior Secured Second Lien Notes Due 2020
On March 12, 2015, EGC issued $1.45 billion in aggregate principal amount of 11.0% senior secured second lien notes due March 15, 2020 (the “11.0% Notes”) pursuant to the Purchase Agreement (the “Purchase Agreement”) by and among EGC, Energy XXI Ltd, our ultimate parent company (the “Parent”), Energy XXI USA, Inc. (“EXXI USA”) and certain of EGC’s wholly owned subsidiaries (together with the Parent and EXXI USA, the “Guarantors”), and Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the initial purchasers named therein (the “Initial Purchasers”). EGC received net proceeds of approximately
254
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
$1.35 billion in the offering after deducting the Initial Purchasers’ discount and direct offering costs. The 11.0% Notes were sold to investors at a discount of 96.313% of principal, for a yield to maturity at issuance of 12.000%. The 11.0% Notes were offered and sold in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”) and were resold to qualified institutional buyers in reliance on Rule 144A of the Securities Act. As such, the 11.0% Notes and the related guarantees have not been, and will not be, registered under the Securities Act or the securities laws of any other jurisdiction. The 11.0% Notes bear interest from the date of their issuance at an annual rate of 11.0% with interest due semi-annually, in arrears, on March 15th and September 15th, beginning September 15, 2015. EGC incurred underwriting and direct offering costs of $41.7 million which have been capitalized and are being amortized over the life of the 11.0% Notes. The effective interest rate on the 11.0% Notes is approximately 12.8%, reflecting amortization of the Initial Purchasers’ discount of $53.5 million as well as the direct offering costs.
The 11.0% Notes were issued pursuant to an indenture, dated March 12, 2015 (the “2015 Indenture”), among EGC, the Guarantors and U.S. Bank National Association, as trustee (the “Trustee”). The 11.0% Notes are secured by second-priority liens on substantially all of EGC and its subsidiary guarantors’ assets and all of EXXI USA’s equity interests in EGC and its interests in certain assets related to the Grand Isle Assets, in each case to the extent such assets secure our Revolving Credit Facility. In the future, the 11.0% Notes may be guaranteed by certain of EGC’s material domestic restricted subsidiaries that incur or guarantee certain indebtedness, including, upon the occurrence of certain events, some or all of EPL and its subsidiaries. The liens securing the 11.0% Notes and the related guarantees are contractually subordinated to the liens on such assets securing our Revolving Credit Facility and any other priority lien debt, to the extent of the value of the collateral securing such obligations, pursuant to the terms of an intercreditor agreement, and to certain other secured indebtedness, to the extent of the value of the assets subject to the liens securing such indebtedness.
The 11.0% Notes are fully and unconditionally guaranteed on a senior basis by the Guarantors and by certain of EGC’s future subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the 2015 Indenture. EXXI USA also guaranteed the notes on a non-recourse basis limited to the value of equity interests in EGC that it pledges to secure its guarantee and the Grand Isle Assets in which it grants a security interest in to secure its guarantee. Although the 11.0% Notes are guaranteed by the Parent and EXXI USA, the Parent and EXXI USA will not, subject to certain exceptions, be subject to the restrictive covenants in the 2015 Indenture.
On or after September 15, 2017, EGC will have the right to redeem all or some of the 11.0% Notes at specified redemption prices (initially 108.25% of the principal amount, declining to par on or after July 15, 2019), plus accrued and unpaid interest. Prior to September 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 11.0% Notes originally issued at a price equal to 111.0% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to September 15, 2017, EGC may redeem all or part of the 11.0% Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC will be required to offer to purchase all outstanding 11.0% Notes if a “triggering event” occurs, at a price of 100% of the principal amount of the 11.0% Notes purchased plus accrued and unpaid interest to the date of purchase. For this purpose, a “triggering event” will be deemed to occur (i) on the 30th day prior to the stated maturity date of the 9.25% Senior Notes, if on such date the aggregate outstanding principal amount of all such notes that have not been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million, or (ii) on the 30th day prior to the stated maturity date of the 8.25% Senior Notes, if on such date the aggregate outstanding principal amount of the 8.25% Senior Notes that shall not have been repurchased, redeemed, discharged, defeased or called for redemption under specified arrangements, exceeds $250.0 million. If a change of control, as defined in the 2015 Indenture, occurs, each
255
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
holder of the 11.0% Notes will have the right to require EGC to repurchase all or any part of their 11.0% Notes at a price equal to 101% of the aggregate principal amount plus accrued and unpaid interest.
The 2015 Indenture restricts EGC’s ability and the ability of its restricted subsidiaries to: (i) transfer or sell assets; (ii) make loans or investments; (iii) pay dividends, redeem subordinated indebtedness or make other restricted payments; (iv) incur or guarantee additional indebtedness or issue disqualified capital stock; (v) create or incur certain liens; (vi) incur dividend or other payment restrictions affecting certain subsidiaries; (vii) consummate a merger, consolidation or sale of all or substantially all of EGC’s assets; (viii) enter into transactions with affiliates; and (ix) engage in business other than the oil and gas business. These covenants are subject to a number of important exceptions and qualifications.
8.25% Senior Notes Due 2018
On June 3, 2014, EGC assumed the 8.25% Senior Notes in the EPL Acquisition which consist of $510 million in aggregate principal amount issued under an indenture dated as of February 14, 2011 (the “2011 Indenture”). The 8.25% Senior Notes are fully and unconditionally guaranteed, jointly and severally, on an unsecured senior basis initially by each of EPL’s existing direct and indirect domestic subsidiaries. The 8.25% Senior Notes will mature on February 15, 2018. On April 18, 2014, EPL entered into a supplemental indenture (the “Supplemental Indenture”) to the 2011 Indenture, by and among EPL, the guarantors party thereto, and U.S. Bank National Association, as trustee, governing EPL’s 8.25% Senior Notes. EPL entered into the Supplemental Indenture after the receipt of the requisite consents from the holders of the 8.25% Senior Notes in accordance with the Supplemental Indenture. The Supplemental Indenture amended the terms of the 2011 Indenture governing the 8.25% Senior Notes to waive EPL’s obligation to make and consummate an offer to repurchase the 8.25% Senior Notes at 101% of the principal amount thereof plus accrued and unpaid interest. We paid an aggregate cash payment of $1.2 million (equal to $2.50 per $1,000 principal amount of 8.25% Senior Notes for which consents were validly delivered and unrevoked). The 8.25% Senior Notes are callable at 104.125% starting February 15, 2015 with such premium declining to zero by February 15, 2017.
6.875% Senior Notes Due 2024
On May 27, 2014, EGC issued the 6.875% Senior Notes which consist of $650 million in aggregate principal amount due March 15, 2024. On November 25, 2014, we filed a registration statement with the Securities and Exchange Commission (“SEC”) for an offer to exchange the 6.875% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 6.875% Senior Notes. On May 1, 2015, we filed Amendment No. 1 to the registration statement and the registration statement was declared effective by the SEC. The exchange offer commenced on May 4, 2015, and we currently expect to complete the exchange offer in June 2015. EGC incurred underwriting and direct offering costs of approximately $11 million which were capitalized and are being amortized over the life of the 6.875% Senior Notes.
On or after March 15, 2019, EGC will have the right to redeem all or some of the 6.875% Senior Notes at specified redemption prices specified in the indenture, plus accrued and unpaid interest. Prior to March 15, 2017, EGC may redeem up to 35% of the aggregate principal amount of the 6.875% Senior Notes originally issued at a price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, in an amount not greater than the proceeds of certain equity offerings and provided that (i) at least 65% of the aggregate principal amount of the 6.875% Senior Notes remains outstanding immediately after giving effect to such redemption; and (ii) any such redemption is made within 180 days of the date of closing of such equity offering. In addition, prior to March 15, 2019, EGC may redeem all or part of the 6.875% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 6.875% Senior Notes upon a change of control at a purchase price in cash equal to 101% of the aggregate principal amount of the 6.875% Senior Notes
256
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
repurchased plus accrued and unpaid interest and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 6.875% Senior Notes.
The indenture governing the 6.875% Senior Notes, among other things, limits EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidation or sale of all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
3.0% Senior Convertible Notes Due 2018
On November 18, 2013, the Parent sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Parent incurred underwriting and direct offering costs of $7.6 million which have been capitalized and are being amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the election of the Parent, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
Upon conversion, the Parent will be obligated to pay or deliver, as the case may be, cash, shares of common stock or a combination of cash and shares of common stock, at its election. If the conversion obligation is satisfied solely in cash or through payment and delivery, as the case may be, of a combination of cash and shares of common stock, the amount of cash and shares of common stock, if any, due upon conversion will be based on a daily conversion value (as described in the indenture governing the 3.0% Senior Convertible Notes) calculated on a proportionate basis for each trading day in a 25 consecutive trading-day conversion period (as described in the indenture governing the 3.0% Senior Convertible Notes). Upon any conversion, subject to certain exceptions, holders of the 3.0% Senior Convertible Notes will receive interest payable in cash, shares of common stock or a combination of cash and shares of common stock paid or delivered, as the case may be.
If holders elect to convert the notes in connection with certain fundamental change transactions described in the indenture governing the 3.0% Senior Convertible Notes, the conversion rate will increase by a number of additional shares determined by reference to the provisions contained in the indenture governing the 3.0% Senior Convertible Notes based on the effective date of, and the price paid (or deemed paid) per share of common stock in, such make-whole fundamental change. If holders of common stock receive only cash in connection with certain make-whole fundamental changes, the price paid (or deemed paid) per share will be the cash amount paid per share. Otherwise, the price paid (or deemed paid) per share will be equal to the average of the closing sale prices of common stock on the five trading days prior to, but excluding, the effective date of such make-whole fundamental change.
If the Parent undergoes a fundamental change (as defined in the indenture governing the 3.0% Senior Convertible Notes) prior to maturity, holders of the 3.0% Senior Convertible Notes will have the right, at their option, to require the Parent to repurchase for cash some or all of their notes at a repurchase price equal to 100% of the principal amount of the notes being repurchased, plus accrued and unpaid interest (including additional interest, if any) to, but excluding, the fundamental change repurchase date.
257
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
For accounting purposes, the $400 million aggregate principal amount of 3.0% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3.0% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the original issue discount of $63.4 million is being amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.
7.5% Senior Notes Due 2021
On September 26, 2013, EGC issued $500 million face value of 7.5% unsecured senior notes due December 15, 2021 at par (the “7.5% Senior Notes”). In April 2014, we filed Amendment No. 1 to the registration statement with the SEC for an offer to exchange the 7.5% Senior Notes with a new series of freely tradable notes having substantially identical terms as the 7.5% Senior Notes. The registration statement was declared effective by the SEC on April 25, 2014 and we completed the exchange on May 23, 2014. EGC incurred underwriting and direct offering costs of $8.6 million which have been capitalized and are being amortized over the life of the 7.5% Senior Notes.
On or after December 15, 2016, EGC will have the right to redeem all or some of the 7.5% Senior Notes at specified redemption prices, plus accrued and unpaid interest. Prior to December 15, 2016, EGC may redeem up to 35% of the aggregate principal amount of the 7.5% Senior Notes originally issued at a price equal to 107.5% of the aggregate principal amount in an amount not greater than the proceeds of certain equity offerings. In addition, prior to December 15, 2016, EGC may redeem all or part of the 7.5% Senior Notes at a price equal to 100% of their aggregate principal amount plus a make-whole premium and accrued and unpaid interest. EGC is required to make an offer to repurchase the 7.5% Senior Notes upon a change of control and from the net proceeds of certain asset sales under specified circumstances, each of which as defined in the indenture governing the 7.5% Senior Notes.
The indenture governing the 7.5% Senior Notes limits, among other things, EGC’s ability and the ability of our restricted subsidiaries to transfer or sell assets, make loans or investments, pay dividends, redeem subordinated indebtedness or make other restricted payments, incur or guarantee additional indebtedness or issue disqualified capital stock, create or incur certain liens, incur dividend or other payment restrictions affecting certain subsidiaries, consummate a merger, consolidate or sell all or substantially all of our assets, enter into transactions with affiliates and engage in business other than the oil and gas business.
7.75% Senior Notes Due 2019
On February 25, 2011, EGC issued $250 million face value of 7.75% unsecured senior notes due June 15, 2019 at par (the “7.75% Old Senior Notes”). It exchanged the full $250 million aggregate principal amount of the 7.75% Old Senior Notes for $250 million aggregate principal amount of newly issued notes registered under the Securities Act (the “7.75% Senior Notes”) on July 7, 2011. The 7.75% Senior Notes bear identical terms and conditions as the 7.75% Old Senior Notes.
The 7.75% Senior Notes are callable at 103.875% starting June 15, 2015, with such premium declining to zero on June 15, 2017. EGC incurred underwriting and direct offering costs of $3.1 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 7.75% Senior Notes under various circumstances and is required to make an offer to repurchase the 7.75% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 7.75% Senior Notes.
258
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
9.25% Senior Notes Due 2017
On December 17, 2010, EGC issued $750 million face value of 9.25% unsecured senior notes due December 15, 2017 at par (the “9.25% Old Senior Notes”). It exchanged $749 million aggregate principal amount of the 9.25% Old Senior Notes for $749 million aggregate principal amount of newly issued notes (the “9.25% Senior Notes”) registered under the Securities Act on July 8, 2011. The 9.25% Senior Notes bear identical terms and conditions as the 9.25% Old Senior Notes. The trading restrictions on the remaining $1 million face value of the 9.25% Old Senior Notes were lifted on December 17, 2011.
The 9.25% Senior Notes are callable at 104.625% starting December 15, 2014, with such premium declining to zero by December 15, 2016. EGC incurred underwriting and direct offering costs of $15.4 million which were capitalized and are being amortized over the life of the notes.
EGC has the right to redeem the 9.25% Senior Notes under various circumstances and is required to make an offer to repurchase the 9.25% Senior Notes upon a change of control and from the net proceeds of asset sales under specified circumstances, each of which as defined in the indenture governing the 9.25% Senior Notes.
4.14% Promissory Note
In September 2012, we entered into a promissory note of $5.5 million to acquire other property and equipment. Under this note, we are required to make a monthly payment of approximately $52,000 and one lump-sum payment of $3.3 million at maturity in October 2017. This note carries an interest rate of 4.14% per annum.
Derivative Instruments Premium Financing
We finance premiums on derivative instruments that we purchase with our hedge counterparties. Substantially all of our hedge transactions are with lenders under the Revolving Credit Facility. Derivative instruments premium financing is accounted for as debt and this indebtedness is pari passu with borrowings under the Revolving Credit Facility. The derivative instruments premium financing is structured to mature when the derivative instrument settles so that we realize the value, net of derivative instrument premium financing. As of March 31, 2015 and June 30, 2014, our outstanding derivative instruments premium financing discounted at our approximate borrowing cost of 2.5% per annum totaled $16.5 million and $21.0 million, respectively.
259
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 7 — Long-Term Debt – (continued)
Interest Expense
For the three and nine months ended March 31, 2015 and 2014, interest expense consisted of the following (in thousands):
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Revolving Credit Facility | $ | 7,526 | $ | 2,782 | $ | 21,901 | $ | 10,327 | ||||||||
11.0% Senior Secured Second Lien Notes due 2020 | 8,740 | — | 8,740 | — | ||||||||||||
8.25% Senior Notes due 2018 | 10,518 | — | 31,556 | — | ||||||||||||
6.875% Senior Notes due 2024 | 11,172 | — | 33,516 | — | ||||||||||||
3.0% Senior Convertible Notes due 2018 | 2,959 | 3,000 | 9,008 | 4,267 | ||||||||||||
7.50% Senior Notes due 2021 | 9,375 | 9,375 | 28,125 | 19,167 | ||||||||||||
7.75% Senior Notes due 2019 | 4,843 | 4,844 | 14,531 | 14,531 | ||||||||||||
9.25% Senior Notes due 2017 | 17,343 | 17,344 | 52,031 | 52,031 | ||||||||||||
4.14% Promissory Note due 2017 | 47 | 53 | 146 | 157 | ||||||||||||
Amortization of debt issue cost – Revolving Credit Facility | 9,845 | 603 | 11,902 | 2,264 | ||||||||||||
Accretion of original debt issue discount, 11.0% Notes due 2020 | 418 | — | 418 | — | ||||||||||||
Amortization of debt issue cost – 11.0% Notes due 2020 | 327 | — | 327 | — | ||||||||||||
Amortization of fair value premium – 8.25% Senior Notes due 2018 | (2,608 | ) | — | (7,712 | ) | — | ||||||||||
Amortization of debt issue cost – 6.875% Senior Notes due 2024 | 282 | — | 845 | — | ||||||||||||
Accretion of original debt issue discount, 3.0% Senior Convertible Notes due 2018 | 2,794 | 3,132 | 8,355 | 4,438 | ||||||||||||
Amortization of debt issue cost – 3.0% Senior Convertible Notes due 2018 | 358 | 516 | 1,070 | 547 | ||||||||||||
Amortization of debt issue cost – 7.50% Senior Notes due 2021 | 263 | 260 | 788 | 520 | ||||||||||||
Amortization of debt issue cost – 7.75% Senior Notes due 2019 | 97 | 97 | 291 | 291 | ||||||||||||
Amortization of debt issue cost – 9.25% Senior Notes due 2017 | 552 | 551 | 1,655 | 1,655 | ||||||||||||
Derivative instruments financing and other | 188 | 143 | 710 | 831 | ||||||||||||
$ | 85,039 | $ | 42,700 | $ | 218,203 | $ | 111,026 |
260
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 8 — Notes Payable
On June 3, 2014, we entered into a note with AFCO Credit Corporation to finance a portion of our insurance premiums. The note was for a total face amount of $22.0 million and bears interest at an annual rate of 1.723%. The note amortizes over the remaining term of the insurance, which matures May 3, 2015. The balance outstanding as of March 31, 2015 was $4.0 million.
On July 1, 2014 and on August 1, 2014, we entered into two notes with AFCO Credit Corporation to finance a portion of our insurance premiums. The notes were for a total face amount of $4.2 million and bear interest at an annual rate of 1.923%. The notes amortize over the remaining term of the insurance, which mature May 1, 2015. The balance outstanding as of March 31, 2015 was $0.9 million.
Note 9 — Asset Retirement Obligations
The following table describes the changes to our asset retirement obligations (in thousands):
Balance at June 30, 2014 | $ | 559,834 | ||
Liabilities incurred and true-up to liabilities settled | 20,411 | |||
Liabilities settled | (77,235 | ) | ||
Liabilities sold | (3,308 | ) | ||
Accretion expense | 37,723 | |||
Total balance at March 31, 2015 | 537,425 | |||
Less current portion | 68,392 | |||
Long-term balance at March 31, 2015 | $ | 469,033 |
Note 10 — Derivative Financial Instruments
We enter into hedging transactions to reduce exposure to fluctuations in the price of crude oil and natural gas. We enter into hedging transactions with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We use financially settled crude oil and natural gas puts, put spreads, swaps, zero-cost collars and three-way collars. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the consolidated balance sheets. Any gains or losses resulting from the change in fair value from hedging transactions are recorded as gain (loss) on derivative financial instruments in earnings as a component of revenue on the consolidated statements of operations.
With a financially settled purchased put, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the hedged price of the transaction. A put spread is a combination of a bought put and a sold put. If the settlement price is below the sold put strike price, we receive the difference between the two strike prices. If the settlement price is below the bought put strike price but above the sold put strike price, we receive the difference between the bought put strike price and the settlement price. There is no settlement if the underlying price settles above the bought put strike price. With a swap, the counterparty is required to make a payment to us if the settlement price for a settlement period is below the hedged price for the transaction, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the hedged price for the transaction. With a zero-cost collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. A three-way collar is a combination of options consisting of a sold call, a purchased put and a sold put. The sold call establishes a maximum price we will receive for the volumes under contract. The purchased put establishes a minimum
261
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 10 — Derivative Financial Instruments – (continued)
price unless the market price falls below the sold put, at which point the minimum price would be the reference price (i.e., NYMEX WTI and/or BRENT, IPE) plus the difference between the purchased put and the sold put strike price.
Most of our crude oil production is Heavy Louisiana Sweet (“HLS”). We include contracts indexed to ICE Brent futures and Argus-LLS futures in our hedging portfolio to closely align and manage our exposure to the associated price risk.
The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of hedging arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements.
Subsequent to the EPL Acquisition, we assumed EPL’s existing hedges with contract terms beginning June 2014 through December 2015. EPL’s oil contracts were primarily swaps and benchmarked to Argus-LLS and Brent. During the quarter ended December 31, 2014, we monetized all the calendar 2015 Brent swap contracts keeping one natural gas contract intact.
As of March 31, 2015, we had the following net open crude oil derivative positions:
Remaining Contract Term | Type of Contract | Index | Volumes (MBbls) | Weighted Average Contract Price | ||||||||||||||||||||||||
Collars/Put | ||||||||||||||||||||||||||||
Sub Floor | Floor | Ceiling | ||||||||||||||||||||||||||
April 2015 – December 2015 | Three-Way Collars | ARGUS-LLS | 5,500 | $ | 32.50 | $ | 45.00 | $ | 75.00 | |||||||||||||||||||
April 2015 – December 2015 | Collars | ARGUS-LLS | 1,375 | 80.00 | 123.38 | |||||||||||||||||||||||
April 2015 – December 2015 | Collars | NYMEX-WTI | 413 | 75.00 | �� | 85.00 | ||||||||||||||||||||||
April 2015 – December 2015 | Bought Put | NYMEX-WTI | 1,053 | 90.00 | ||||||||||||||||||||||||
April 2015 – December 2015 | Sold Put | NYMEX-WTI | (1,053 | ) | 90.00 | |||||||||||||||||||||||
January 2016 – December 2016 | Collars | NYMEX-WTI | 5,124 | 51.43 | 74.70 |
As of March 31, 2015, we had the following net open natural gas derivative position:
Remaining Contract Term | Type of Contract | Index | Volumes (MMBtu) | Swaps Fixed Price | ||||||||||||
April 2015 – December 2015 | Swaps | NYMEX-HH | 1,183 | $ | 4.31 |
262
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 10 — Derivative Financial Instruments – (continued)
The fair values of derivative instruments in our consolidated balance sheets were as follows (in thousands):
Asset Derivative Instruments | Liability Derivative Instruments | |||||||||||||||||||||||||||||||
March 31, 2015 | June 30, 2014 | March 31, 2015 | June 30, 2014 | |||||||||||||||||||||||||||||
Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | |||||||||||||||||||||||||
Derivative financial instruments | Current | $ | 104,660 | Current | $ | 17,380 | Current | $ | 51,838 | Current | $ | 47,912 | ||||||||||||||||||||
Non-Current | 20,860 | Non-Current | 9,595 | Non-Current | 11,164 | Non-Current | 10,866 | |||||||||||||||||||||||||
Total Gross Derivative Commodity Instruments subject to enforceable master netting agreement | 125,520 | 26,975 | 63,002 | 58,778 | ||||||||||||||||||||||||||||
Derivative financial instruments | Current | (51,838 | ) | Current | (15,955 | ) | Current | (51,838 | ) | Current | (15,955 | ) | ||||||||||||||||||||
Non-Current | (11,093 | ) | Non-Current | (6,560 | ) | Non-Current | (11,093 | ) | Non-Current | (6,560 | ) | |||||||||||||||||||||
Gross amounts offset in Balance Sheets | (62,931 | ) | (22,515 | ) | (62,931 | ) | (22,515 | ) | ||||||||||||||||||||||||
Net amounts presented in Balance Sheets | Current | 52,822 | Current | 1,425 | Current | — | Current | 31,957 | ||||||||||||||||||||||||
Non-Current | 9,767 | Non-Current | 3,035 | Non-Current | 71 | Non-Current | 4,306 | |||||||||||||||||||||||||
$ | 62,589 | $ | 4,460 | $ | 71 | $ | 36,263 |
The following table presents information about the components of the gain (loss) on derivative instruments (in thousands).
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
Gain (loss) on derivative financial instruments | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Cash Settlements, net of amortization of purchased put premiums: | $ | 34,491 | $ | (7,089 | ) | $ | 77,710 | $ | (11,788 | ) | ||||||
Proceeds from monetizations, net | 73,117 | — | 102,354 | — | ||||||||||||
Change in fair value | (90,645 | ) | (260 | ) | 85,086 | (46,915 | ) | |||||||||
Total gain (loss) on derivative financial instruments | $ | 16,963 | $ | (7,349 | ) | $ | 265,150 | $ | (58,703 | ) |
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. At March 31, 2015, we had no deposits for collateral with our counterparties.
Note 11 — Income Taxes
We are a Bermuda company and are generally not subject to income tax in Bermuda. We operate through our various subsidiaries in the United States; accordingly, income taxes have been provided based upon U.S. tax laws and rates as they apply to our current ownership structure. We estimate our annual effective tax rate for the current fiscal year and apply it to interim periods; however, during the second quarter of fiscal year 2015, we recorded a goodwill impairment charge of $329 million (see Note 4 — Goodwill of Notes within these quarterly consolidated financial statements). In light of the form of the transaction related to the EPL Acquisition on June 3, 2014, the goodwill recognized as a result of the EPL Acquisition during fiscal year
263
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 11 — Income Taxes – (continued)
2014 did not have tax basis. Therefore, the goodwill impairment is nondeductible for federal and state income tax purposes. Currently, our estimated annual effective tax/(benefit) rate is approximately (35.4)% excluding the effect of the goodwill impairment charge. For purposes of computing our interim provision (benefit) for income taxes, the goodwill impairment charge is treated as a discrete item in the quarter in which it occurred. Our actual effective tax/(benefit) rates for the three and nine months ended March 31, 2015 were (36.9)% and (23.8)%, respectively. The variance from the U.S. statutory rate of 35% is primarily due to two elements: (i) the impairment of goodwill and (ii) a decrease to the statutory rate due to the presence of common permanent difference items (such as non-deductible compensation, meals and entertainment expenses) and non-U.S. activity in our Bermuda parent that is ineligible for U.S. tax benefit. Additionally, our Bermuda companies continue to record income tax expense reflecting 30% U.S. withholding tax on any interest (and interest equivalent) accrued on indebtedness of the U.S. companies held by the Bermuda companies. We have accrued an additional withholding obligation of $7.8 million for the nine months ended March 31, 2015.
Under Louisiana law, companies are required to file tax returns on a separate company basis; as such, EPL and EGC will not file a combined nor consolidated Louisiana income tax return. Our valuation allowance of $23.8 million relates to Energy XXI’s separate company Louisiana net operating loss (“NOL”) carryovers that we do not currently believe, on a more likely-than-not basis, will be realized in future years due to the current focus on offshore operations. However, an intercompany transaction generated current year Louisiana-only taxable income this period; thus we have released $3.0 million of previously recorded Louisiana valuation allowance as a discrete item this quarter. No valuation allowance has been (or is expected to be) recorded with respect to any Louisiana NOLs generated by EPL, or on consolidated U.S. federal NOL carryovers, since management believes that there is sufficient future taxable income available arising from the future reversal of existing temporary differences previously recorded attributable to the excess of the book carrying value of oil and gas properties over their corresponding tax bases. Management is not relying on other sources of possible future taxable income in concluding that no valuation allowance is needed on EPL’s Louisiana NOLs or consolidated U.S federal NOL carryovers.
During the nine months ended March 31, 2015, we made cash withholding tax payments of $0.8 million on management fees paid to our Bermuda entities. While we have not made a cash income tax payment during the nine months ended March 31, 2015, in light of expected income in this fiscal year and subsequent years, estimated tax payments for Alternative Minimum Tax (“AMT”) in subsequent quarters may be required. We expect any AMT payment to be fully creditable against future regular tax obligations; thus, these AMT payments have no impact on our estimated annual effective tax rate.
On January 12, 2015, the U.S. Internal Revenue Service (“IRS”) formally notified us that they had completed their examination of our U.S. federal income tax return for the year ended June 30, 2013, and that no changes were proposed to the tax reported (zero) or any tax attribute carried forward.
Note 12 — Stockholders’ Equity
Common Stock
Our common stock trades on the NASDAQ under the symbol “EXXI.” Our shareholders are entitled to one vote for each share of common stock held on all matters to be voted on by shareholders. We have 200,000,000 authorized common shares, par value of $0.005 per share.
We paid cash dividends of $0.01 and $0.25 per share to holders of our common stock during the three and nine months ended March 31, 2015, respectively. We paid cash dividends of $0.12 and $0.36 per share to holders of our common stock during the three and nine months ended March 31, 2014, respectively.
On May 5, 2015 the Board of Directors declared a dividend of $.01 per common share payable on June 12, 2015 to holders of record on May 29, 2015.
264
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 12 — Stockholders’ Equity – (continued)
Pursuant to the stock repurchase program approved by our Board of Directors in May 2013, through June 30, 2014, we paid $166.8 million to repurchase 6,639,363 shares of our common stock at a weighted average price per share, excluding fees, of $25.14. As of March 31, 2015, $83.2 million remains available for repurchase under the share repurchase program. We do not intend to repurchase any additional shares of our common stock at this time.
In addition, concurrently with the offering of our 3.0% Senior Convertible Notes in November 2013, 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.
In February 2014, we retired 2,087,126 shares of our common stock, resulting in 7,329,100 shares of common stock being held in treasury. On June 3, 2014, we reissued the entire 7,329,100 shares of common stock in treasury as part of our common stock issued to EPL stockholders upon merger.
As discussed in Note 7 — Long-Term Debt in the Notes to these quarterly consolidated financial statements, in November 2013, we sold $400 million of 3.0% Senior Convertible Notes. The $63.4 million allocated to the equity portion of the 3.0% Senior Convertible Notes, less offering costs of $1.4 million, were recorded as an increase in additional paid in capital.
As discussed in Note 3 — Acquisitions and Dispositions in the Notes to these quarterly consolidated financial statements, upon closing of the EPL Acquisition, we issued 23,320,955 shares of our common stock, including the treasury shares, as noted above, as part of the Merger Consideration.
Preferred Stock
Our bye-laws authorize the issuance of 7,500,000 shares of preferred stock. Our Board of Directors is empowered, without shareholder approval, to issue preferred stock with dividend, liquidation, conversion, voting or other rights that could adversely affect the voting power or other rights of the holders of common stock. Shares of previously issued preferred stock that have been cancelled are available for future issuance.
Dividends on both the 5.625% Perpetual Convertible Preferred Stock (“5.625% Preferred Stock”) and the 7.25% Perpetual Convertible Preferred Stock (“7.25% Preferred Stock”) are payable quarterly in arrears on March 15, June 15, September 15 and December 15 of each year.
Dividends on both the 5.625% Preferred Stock and the 7.25% Preferred Stock may be paid in cash, shares of our common stock, or a combination thereof. If we elect to make payment in shares of common stock, such shares shall be valued for such purposes at 95% of the market value of our common stock as determined on the second trading day immediately prior to the record date for such dividend.
The 5.625% Preferred Stock is convertible into 9.8353 shares of the Company’s common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 5.625% Preferred Stock Certificate of Designation. At March 31, 2015, the conversion rate was 10.4772 common shares per preferred share. On or after December 15, 2013, the Company may cause the 5.625% Preferred Stock to be automatically convertible into common stock at the then prevailing conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 130% of the then-prevailing conversion price.
The 7.25% Preferred Stock is convertible into 8.77192 shares of the Company’s common stock at the conversion rate and price in effect on the conversion date. The conversion rate is subject to adjustment as set forth in Section 7 of the 7.25% Preferred Stock Certificate of Designation. At March 31, 2015, the conversion rate was 9.3177 common shares per preferred share. On or after December 15, 2014, the Company may cause the 7.25% Preferred Stock to be automatically convertible into common stock at the then prevailing
265
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 12 — Stockholders’ Equity – (continued)
conversion rate if, for at least 20 trading days in a period of 30 consecutive trading days, the daily average price of the Company’s common stock equals or exceeds 150% of the then-prevailing conversion price.
Conversions of Preferred Stock
During the nine months ended March 31, 2015, we canceled and converted a total of 5,000 shares of our 7.25% Preferred Stock into a total of 46,472 shares of common stock using a conversion rate of 9.2940 common shares per preferred share. During the nine months ended March 31, 2015, we also canceled and converted one share of our 5.625% Preferred Stock into 11 shares of common stock using a conversion rate of 10.2409 common shares per preferred share.
During the nine months ended March 31, 2014, we canceled and converted a total of 428 shares of our 5.625% Preferred Stock into a total of 4,288 shares of common stock using a conversion rate ranging from 10.0147 to 10.0579 common shares per preferred share.
Note 13 — Supplemental Cash Flow Information
The following table presents our supplemental cash flow information (in thousands):
Nine Months Ended March 31, | ||||||||
2015 | 2014 | |||||||
Cash paid for interest | $ | 170,582 | $ | 64,061 | ||||
Cash paid for income taxes | 840 | 3,362 |
The following table presents our non-cash investing and financing activities (in thousands):
Nine Months Ended March 31, | ||||||||
2015 | 2014 | |||||||
Financing of insurance premiums | $ | 931 | $ | 2,355 | ||||
Derivative instruments premium financing | 12,025 | 3,493 | ||||||
Additions to property and equipment by recognizing asset retirement obligations | 20,411 | 38,513 |
Note 14 — Employee Benefit Plans
The Energy XXI Services, LLC 2006 Long-Term Incentive Plan (“Incentive Plan”). We maintain an incentive and retention program for our employees. Participation shares (or “Restricted Stock Units”) are issued from time to time at a value equal to our common share price at the time of issue. The Restricted Stock Units generally vest equally over a three-year period. When vesting occurs, we pay the employee an amount equal to the then current common share price times the number of Restricted Stock Units.
Performance Units
Units issued through Fiscal Year 2014. For fiscal 2014, 2013 and 2012, we also awarded performance units. Of the total performance units awarded, 25% are time-based performance units (“Time-Based Performance Units”) and 75% are Total Shareholder Return Performance-Based Units (“TSR Performance-Based Units”). Both the Time-Based Performance Units and TSR Performance-Based Units vest equally over a three-year period.
Time-Based Performance Units. The amount due to the employee at the vesting date is equal to the grant date unit value of $5.00 plus the appreciation in the stock price over the performance period, multiplied by the number of units that vest. For the fiscal years 2012, 2013 and 2014 grants, the initial stock prices were $33.20, $24.50, and $22.48 respectively.
266
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 14 — Employee Benefit Plans – (continued)
TSR Performance-Based Units. For each 2014, 2013 and 2012 TSR Performance-Based Unit, the executive will receive a cash payment equal to the grant date unit value of $5.00 multiplied by (a) the cumulative percentage change in the price per share of the Company’s common stock from the date on which the TSR Performance-Based Units were granted (the “Total Shareholder Return”) and (b) the TSR Unit Number Modifier.
In addition, the employee may have the opportunity to earn additional compensation based on the Company’s Total Shareholder Return at the end of the third Performance Period for the 2014, 2013 and 2012 grants.
At our discretion, at the time the Restricted Stock Units and Performance Units vest, the amount due employees will be settled in either common shares or cash. Historically, we have settled all vesting Restricted Stock Units awards in cash. The July 21, 2014 vesting of the July 21, 2013, 2012 and 2011 Performance Unit awards were settled 50% in common stock and future vesting of the Performance Units may be settled in stock at the discretion of our Board of Directors. Upon a change in control of the Company, as defined in the Incentive Plan, all outstanding Restricted Stock Units and Performance Units become immediately vested and payable.
Changes for Fiscal 2015 Performance Unit Grants. For the performance unit awards granted in fiscal 2015, the Remuneration Committee of the Board of Directors has determined to change the performance measure within the Incentive Plan from absolute TSR to relative TSR compared to a performance peer group. Under this plan, executives will receive no payout for TSR performance below the 25th percentile, a 50% payout for TSR performance at the 25th percentile, a 100% payout for TSR performance at the median, and 200% payout for performance at or above the 75th percentile. Payouts under this plan are capped at target if absolute total shareholder return is negative. In addition, the Remuneration Committee has decided to eliminate the use of a $5 notional unit and instead will denominate units based on the stock price on the grant date. The Remuneration Committee also decided to eliminate the make-up feature for the fiscal 2015 awards. The awards for fiscal 2015 have continued to be granted 25% in the form of Time-Based Performance Unit awards and 75% in the form of TSR Performance-Based Unit awards.
We recognized compensation expense (benefit) related to our outstanding Restricted Stock Units and Performance Units as follows (in thousands):
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Restricted Stock Units | $ | 6,124 | $ | 1,974 | $ | 10,102 | $ | 10,303 | ||||||||
Performance Units | 838 | (1,780 | ) | (4,770 | ) | 11,048 | ||||||||||
Total compensation expense recognized | $ | 6,962 | $ | 194 | $ | 5,332 | $ | 21,351 |
As of March 31, 2015, we had 4,481,074 unvested Restricted Stock Units and 2,469,250 Time-Based Performance Units and 822,000 TSR Performance Based Units.
Non-Executive Director Compensation. On November 7, 2011, the Remuneration Committee approved the director compensation program which provides for an annual stock award of $175,000 worth of shares. The equity retainer is paid in Common Shares in an amount equivalent to $175,000 using our closing stock price on the date of the Annual General Meeting, which represents the grant date fair value computed in accordance with FASB Accounting Standards Codification Topic 718. For the fiscal year 2015, each director (except our two recently appointed directors) was awarded 26,396 Common Shares based on a $6.63 closing price on the date of the 2014 Annual General Meeting. Our two recently appointed directors were awarded a pro-rated amount based on their service as directors beginning on December 15, 2014, which awards totaled
267
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 14 — Employee Benefit Plans – (continued)
63,406 Common Shares each based on a $2.45 closing price on the date of appointment of December 15, 2014. The shares will vest on the date of the 2015 Annual General Meeting. See Note 15 — Related Party Transactions within these quarterly consolidated financial statements for information regarding Restricted Stock Units and consulting fees paid to one of the recently appointed directors for his services as our Interim Chief Strategic Officer.
Note 15 — Related Party Transactions
We have a 20% interest in EXXI M21K and account for this investment using the equity method. EXXI M21K is the guarantor of a $100 million line of credit entered into by M21K. See Note 6 — Equity Method Investments within these quarterly consolidated financial statements.
We have provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K for the EP Energy property acquisition estimated at $65 million and $1.8 million, respectively. For the LLOG Exploration acquisition, we guaranteed payment of asset retirement obligations by M21K estimated at $36.7 million. For the Eugene Island 330 and South Marsh Island 128 properties purchase, we guaranteed payment of asset retirement obligation by M21K estimated at $18.6 million. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the three and nine months ended March 31, 2015, we have received $0.9 million and $2.8 million, respectively, related to such guarantees. For the three and nine months ended March 31, 2014, we received $0.8 million and $2.2 million, respectively, related to such guarantees.
Prior to the LLOG Exploration acquisition, EGC received a management fee of $0.83 per BOE produced for the EP Energy property acquisition for providing administrative assistance in carrying out M21K operations. In conjunction with the LLOG Exploration acquisition, on September 1, 2013, this fee was increased to $1.15 per BOE produced. However, after the Eugene Island 330 and South Marsh Island 128 properties were purchased on April 1, 2014, this fee was reduced to $0.98 per BOE produced. For the three and nine months ended March 31, 2015, EGC received management fees of $0.7 million and $2.1 million, respectively. For the three and nine months ended March 31, 2014, EGC received management fees of $1.0 million and $2.8 million, respectively.
On April 1, 2014, EXXI GOM sold its interest in the Eugene Island 330 and the South Marsh Island 128 properties to M21K and on June 3, 2014, it sold 100% of its interests in the South Pass 49 field to EPL. See Note 3 — Acquisitions and Dispositions within these quarterly consolidated financial statements.
In order to enhance our ability to pursue alternative financing structures, our Board of Directors appointed one of its members, James LaChance, to serve as our interim Chief Strategic Officer. In that position, Mr. LaChance has pursued discussions with our lenders and noteholders to improve our available capital, leverage ratios and average debt maturity, as directed by our Chief Executive Officer, in consultation with the Board. In light of the significant increase in the amount of time Mr. LaChance is required to spend performing in this new role, on February 23, 2015, we and Mr. LaChance entered into an interim Chief Strategic Officer consulting agreement (the “Consulting Agreement”), with an effective date of January 15, 2015. Under the Consulting Agreement, Mr. LaChance will be paid $200,000 per month for his services as interim Chief Strategic Officer. For the three and nine months ended March 31, 2015, we paid Mr. LaChance consulting fees of $0.5 million under the Consulting Agreement.
In accordance with the Consulting Agreement and based on certain objective criteria as set forth therein, Mr. LaChance received a success fee of $5.3 million in connection with the issuance of the 11.0% Notes, which amount reflects the number of restricted stock units (“RSUs”) awarded at the closing stock price of $3.24 on March 12, 2015. In accordance with the terms of the Consulting Agreement, fifty percent of the success fee was required to be paid to Mr. LaChance in the form of cash-settled RSUs, and Mr. LaChance
268
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 15 — Related Party Transactions – (continued)
elected to receive the remaining 50% of the success fee in the form of RSUs on the same terms, subject to certain limitations. On March 12, 2015, Mr. LaChance was awarded 1,644,737 RSUs based on a price of $3.04 per share, which is the value weighted average price of our common stock for the period from December 1, 2014 through January 31, 2015, as defined by the Consulting Agreement. The RSUs will generally be settled in cash on the 12-month anniversary of the issuance of the 11.0% Notes. The RSUs will be settled earlier if, prior to that 12-month anniversary, a change of control occurs or, subject to certain limitations, if Mr. LaChance is no longer serving on the Board of Directors. On the RSU settlement date, Mr. LaChance will have the option to receive all or part of his RSU cash settlement in shares of our common stock, valued at the closing price on the settlement date. Additionally, the Board may award up to an additional $1 million to Mr. LaChance, based upon qualitative factors to be determined by the Board.
The term of the Consulting Agreement is six months unless terminated earlier upon 30 days’ notice by either party or upon the closing of financing transactions, and may be extended by mutual agreement. Mr. LaChance’s duties as interim Chief Strategic Officer are separate from, and in addition to, his responsibilities as a member of the Board of Directors, and as a result of compensation received for that role, Mr. LaChance is no longer considered an independent director.
Note 16 — Earnings (Loss) per Share
Basic earnings (loss) per share of common stock is computed by dividing net income (loss) available for common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be anti-dilutive, the diluted earnings per share include the impact of convertible preferred stock, restricted stock and other common stock equivalents. The following table sets forth the calculation of basic and diluted earnings (loss) per share (“EPS”) (in thousands, except per share data):
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
2015 (Restated) | 2014 (Restated) | 2015 (Restated) | 2014 (Restated) | |||||||||||||
Net income (loss) | $ | (495,061 | ) | $ | 6,318 | $ | (743,834 | ) | $ | 33,528 | ||||||
Preferred stock dividends | 2,862 | 2,872 | 8,605 | 8,617 | ||||||||||||
Net income (loss) available for common stockholders | $ | (497,923 | ) | $ | 3,446 | $ | (752,439 | ) | $ | 24,911 | ||||||
Weighted average shares outstanding for basic EPS | 94,408 | 70,437 | 94,076 | 73,415 | ||||||||||||
Add dilutive securities | — | 65 | — | 78 | ||||||||||||
Weighted average shares outstanding for diluted EPS | 94,408 | 70,502 | 94,076 | 73,493 | ||||||||||||
Earnings (loss) per share | ||||||||||||||||
Basic | $ | (5.27 | ) | $ | 0.05 | $ | (8.00 | ) | $ | 0.34 | ||||||
Diluted | $ | (5.27 | ) | $ | 0.05 | $ | (8.00 | ) | $ | 0.34 |
For the three and nine months ended March 31, 2015, 8,777,374 and 8,582,708 common stock equivalents, respectively, were excluded from the diluted average shares due to an anti-dilutive effect.
269
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 17 — Commitments and Contingencies
Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows.
Litigation Related to 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, EGC, 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 alleged 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 provided for the acquisition of EPL by Energy XXI. Plaintiffs alleged that (a) EPL’s directors allegedly breached fiduciary duties in connection with the merger and (b) Energy XXI, OpCo, Merger Sub, and EPL allegedly aided and abetted in these alleged breaches of fiduciary duties. Plaintiffs sought to have the merger agreement rescinded and also sought damages and attorneys’ fees.
On January 16, 2015, plaintiffs filed a voluntary notice of dismissal. On January 20, 2015, the Court of Chancery of the State of Delaware entered an order dismissing the lawsuit in its entirety without prejudice.
Subsequent Event. In April 2015, we received letters from the Bureau of Ocean Energy Management (the “BOEM”) stating that certain of our subsidiaries no longer qualify for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. The letters notified us that certain of our subsidiaries must provide supplemental financial assurance and/or bonding for their offshore oil and gas leases, rights-of-way, and rights-of-use and easements that require supplemental bonding. The BOEM has indicated the amount of such required supplemental bonding totals approximately $1.0 billion, which amount is currently being negotiated by us. We are currently evaluating the impact of these BOEM letters on our future consolidated financial position, results of operations and cash flow.
Note 18 — Fair Value of Financial Instruments
Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:
• | Level 1 — quoted prices in active markets for identical assets or liabilities. |
270
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 18 — Fair Value of Financial Instruments – (continued)
• | Level 2 — inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). |
• | Level 3 — unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. |
For cash and cash equivalents, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. For the 11.0% Notes, 9.25% Senior Notes, 8.25% Senior Notes, 7.75% Senior Notes, 7.5% Senior Notes, 6.875% Senior Notes and 3.0% Senior Convertible Notes, the fair value is estimated based on quoted prices in a market that is not an active market, which are Level 2 inputs within the fair value hierarchy. The carrying value of the Revolving Credit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy.
Our commodity derivative instruments consist of financially settled crude oil and natural gas puts, swaps, put spreads, zero-cost collars and three way collars. We estimate the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 10 — Derivative Financial Instruments within these quarterly consolidated financial statements.
The fair values of our stock based units are based on the period-end stock price for our Restricted Stock Units and Time-Based Performance Units and the results of the Monte Carlo simulation model are used for our TSR Performance-Based Units. The Monte Carlo simulation model uses inputs relating to stock price, unit value expected volatility and expected rate of return. A change in any input can have a significant effect on the valuation of the TSR Performance-Based Units.
During the nine months ended March 31, 2015, we did not have any transfers from or to Level 3. The following table sets forth our Level 1 and Level 2 financial assets and liabilities that are accounted for at fair value on a recurring basis (in thousands):
Level 1 | Level 2 | |||||||||||||||
As of March 31, 2015 | As of June 30, 2014 | As of March 31, 2015 | As of June 30, 2014 | |||||||||||||
Assets: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 125,520 | $ | 26,975 | ||||||||
Liabilities: | ||||||||||||||||
Oil and natural gas derivatives | $ | — | $ | — | $ | 63,002 | $ | 58,778 | ||||||||
Restricted stock units | 8,237 | 9,425 | — | — | ||||||||||||
Time-based performance units | 1,558 | 3,698 | — | — | ||||||||||||
Total liabilities | $ | 9,795 | $ | 13,123 | $ | 63,002 | $ | 58,778 |
271
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 18 — Fair Value of Financial Instruments – (continued)
The following table sets forth the carrying values and estimated fair values of our long-term indebtedness which are classified as Level 2 financial instruments (in thousands):
March 31, 2015 | June 30, 2014 | |||||||||||||||
Carrying Value | Estimated Fair Value | Carrying Value | Estimated Fair Value | |||||||||||||
Revolving credit facility | $ | 150,000 | $ | 150,000 | $ | 689,000 | $ | 689,000 | ||||||||
11% Senior Secured Second Lien Notes due 2020 | 1,396,957 | 1,384,750 | — | — | ||||||||||||
8.25% Senior Notes due 2018 | 542,855 | 379,761 | 550,566 | 545,700 | ||||||||||||
6.875% Senior Notes due 2024 | 650,000 | 234,000 | 650,000 | 663,000 | ||||||||||||
3.0% Senior Convertible Notes due 2018 | 351,342 | 119,000 | 342,986 | 396,780 | ||||||||||||
7.5% Senior Notes due 2021 | 500,000 | 192,415 | 500,000 | 541,250 | ||||||||||||
7.75% Senior Notes due 2019 | 250,000 | 108,233 | 250,000 | 269,480 | ||||||||||||
9.25% Senior Notes due 2017 | 750,000 | 518,295 | 750,000 | 806,630 | ||||||||||||
$ | 4,591,154 | $ | 3,086,454 | $ | 3,732,552 | $ | 3,911,840 |
The 11.0% Notes, the 8.25% Senior Notes, the 6.875% Senior Notes, and the 7.5% Senior Notes each contain an option to redeem up to 35% of the aggregate principal amount of the respective notes outstanding with the net cash proceeds of certain equity offerings. Such options are considered embedded derivatives and are classified as Level 3 financial instruments for which the estimated fair values at March 31, 2015 are not material.
The following table describes the changes in our Level 3 financial instruments (in thousands):
Three Months Ended March 31, | Nine Months Ended March 31, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
Liabilities: | ||||||||||||||||
Performance-based performance units | ||||||||||||||||
Balance at beginning of period | $ | 109 | $ | 10,077 | $ | 6,910 | $ | 6,778 | ||||||||
Vested | — | — | — | (7,188 | ) | |||||||||||
Grants charged to general and administrative expense | 266 | (2,587 | ) | (6,535 | ) | 7,900 | ||||||||||
Balance at end of period | $ | 375 | $ | 7,490 | $ | 375 | $ | 7,490 |
Note 19 — Prepayments and Accrued Liabilities
Prepayments and accrued liabilities consist of the following (in thousands):
March 31, 2015 | June 30, 2014 | |||||||
Prepaid expenses and other current assets | ||||||||
Advances to joint interest partners | $ | 8,219 | $ | 10,336 | ||||
Insurance | 7,432 | 37,088 | ||||||
Inventory | 7,849 | 7,020 | ||||||
Royalty deposit | 10,490 | 12,262 | ||||||
Other | 5,618 | 5,824 | ||||||
Total prepaid expenses and other current assets | $ | 39,608 | $ | 72,530 |
272
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 19 — Prepayments and Accrued Liabilities – (continued)
March 31, 2015 | June 30, 2014 | |||||||
Accrued liabilities | ||||||||
Advances from joint interest partners | 3,087 | 2,667 | ||||||
Employee benefits and payroll | 27,595 | 43,480 | ||||||
Interest payable | 56,220 | 26,490 | ||||||
Accrued hedge payable | 1,145 | 7,874 | ||||||
Undistributed oil and gas proceeds | 20,146 | 34,473 | ||||||
Severance taxes payable | 892 | 8,014 | ||||||
Other | 8,489 | 10,528 | ||||||
Total accrued liabilities | $ | 117,574 | $ | 133,526 |
Note 20 — Restatement of Previously Issued Consolidated Financial Statements
Prior to the issuance of this Form 10-K, we determined that the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Consequently, unrealized gains or losses resulting from those derivative financial instruments should have been recorded in our consolidated statements of operations as a component of earnings. Under the cash flow hedge accounting treatment previously applied, we had recorded unrealized gains or losses resulting from changes in the fair value of our derivative financial instruments, net of the related tax impact, in accumulated other comprehensive income or loss until the production month when the associated hedge contracts were settled, at which time gains or losses associated with the settled contracts were reclassified to revenues.
The effects of the restatement on our consolidated financial statements are summarized below:
• | Gains and losses on derivative financial instruments previously reported as changes in accumulated other comprehensive income and as (gain) loss on derivative financial instruments within costs and expenses are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Amounts associated with settled contracts previously reported as oil sales and natural gas sales within revenue are now reported as gain (loss) on derivative financial instruments within revenue; |
• | Ceiling tests previously prepared which included the impact of cash flow hedges within the ceiling have been recalculated changing the historical balances of our oil and natural gas properties and related impairments of oil and natural gas properties and depletion; and |
• | Resulting adjustments required to deferred income taxes and income tax expense (benefit). |
273
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
While these non-cash reclassifications impact revenues, net income (loss) in each period, net income (loss) attributable to common stockholders, and net income (loss) per common share, as well as total stockholders’ equity, they have no material impact on cash flows. Details of the restatement applicable to these quarterly consolidated financial statements are as follows:
As of March 31, 2015 | As of June 30, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Total Current Assets | $ | 836,752 | $ | — | $ | 836,752 | $ | 457,759 | $ | — | $ | 457,759 | ||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | 5,772,316 | 79,517 | 5,851,833 | 6,524,602 | (97,339 | ) | 6,427,263 | |||||||||||||||||
Other property and equipment | 22,759 | — | 22,759 | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | 5,795,075 | 79,517 | 5,874,592 | 6,544,362 | (97,339 | ) | 6,447,023 | |||||||||||||||||
Total Other Assets | 123,999 | — | 123,999 | 436,715 | — | 436,715 | ||||||||||||||||||
Total Assets | $ | 6,755,826 | $ | 79,517 | $ | 6,835,343 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 | |||||||||||
Total Current Liabilities | $ | 400,669 | $ | — | $ | 400,669 | $ | 699,895 | $ | — | $ | 699,895 | ||||||||||||
Deferred Income Taxes | 369,685 | 27,858 | 397,543 | 701,038 | (34,069 | ) | 666,969 | |||||||||||||||||
Other Non-Current Liabilities | 5,073,042 | — | 5,073,042 | 4,240,073 | — | 4,240,073 | ||||||||||||||||||
Total Liabilities | 5,843,396 | 27,858 | 5,871,254 | 5,641,006 | (34,069 | ) | 5,606,937 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | 1 | — | 1 | 1 | — | 1 | ||||||||||||||||||
Common stock | 471 | — | 471 | 468 | — | 468 | ||||||||||||||||||
Additional paid-in capital | 1,842,919 | — | 1,842,919 | 1,837,462 | — | 1,837,462 | ||||||||||||||||||
Accumulated deficit | (1,016,322 | ) | 137,020 | (879,302 | ) | (19,626 | ) | (83,745 | ) | (103,371 | ) | |||||||||||||
Accumulated other comprehensive loss, net of income taxes | 85,361 | (85,361 | ) | — | (20,475 | ) | 20,475 | — | ||||||||||||||||
Total Stockholders’ Equity | 912,430 | 51,659 | 964,089 | 1,797,830 | (63,270 | ) | 1,734,560 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 6,755,826 | $ | 79,517 | $ | 6,835,343 | $ | 7,438,836 | $ | (97,339 | ) | $ | 7,341,497 |
274
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Three Months Ended March 31, 2015 | Three Months Ended March 31, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands, except share information) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | 232,520 | $ | (54,915 | ) | $ | 177,605 | $ | 249,955 | $ | 4,686 | $ | 254,641 | |||||||||||
Natural gas sales | 27,672 | (660 | ) | 27,012 | 35,228 | 2,334 | 37,562 | |||||||||||||||||
Gain (loss) on derivative financial instruments | — | 16,963 | 16,963 | — | (7,349 | ) | (7,349 | ) | ||||||||||||||||
Total Revenues | 260,192 | (38,612 | ) | 221,580 | 285,183 | (329 | ) | 284,854 | ||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 190,174 | (2,227 | ) | 187,947 | 99,899 | (2,191 | ) | 97,708 | ||||||||||||||||
Impairment of oil and natural gas properties | 739,941 | (170,325 | ) | 569,616 | — | — | — | |||||||||||||||||
(Gain) loss on derivative financial instruments | 1,932 | (1,932 | ) | — | (205 | ) | 205 | — | ||||||||||||||||
All other costs and expenses | 162,600 | — | 162,600 | 120,688 | — | 120,688 | ||||||||||||||||||
Total Costs and Expenses | 1,094,647 | (174,484 | ) | 920,163 | 220,382 | (1,986 | ) | 218,396 | ||||||||||||||||
Operating Income | (834,455 | ) | 135,872 | (698,583 | ) | 64,801 | 1,657 | 66,458 | ||||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Loss from equity method investees | (2,646 | ) | 11 | (2,635 | ) | (1,111 | ) | 14 | (1,097 | ) | ||||||||||||||
Other income, net | 1,231 | — | 1,231 | 867 | — | 867 | ||||||||||||||||||
Interest expense | (85,039 | ) | — | (85,039 | ) | (42,700 | ) | — | (42,700 | ) | ||||||||||||||
Total Other Expense, net | (86,454 | ) | 11 | (86,443 | ) | (42,944 | ) | 14 | (42,930 | ) | ||||||||||||||
Income Before Income Taxes | (920,909 | ) | 135,883 | (785,026 | ) | 21,857 | 1,671 | 23,528 | ||||||||||||||||
Income Tax Expense (Benefit) | (336,592 | ) | 46,627 | (289,965 | ) | 14,565 | 2,645 | 17,210 | ||||||||||||||||
Net Income | (584,317 | ) | 89,256 | (495,061 | ) | 7,292 | (974 | ) | 6,318 | |||||||||||||||
Preferred Stock Dividends | 2,862 | — | 2,862 | 2,872 | — | 2,872 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | (587,179 | ) | $ | 89,256 | $ | (497,923 | ) | $ | 4,420 | $ | (974 | ) | $ | 3,446 | |||||||||
Earnings per Share | ||||||||||||||||||||||||
Basic | $ | (6.22 | ) | $ | (5.27 | ) | $ | 0.06 | $ | 0.05 | ||||||||||||||
Diluted | $ | (6.22 | ) | $ | (5.27 | ) | $ | 0.06 | $ | 0.05 | ||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||||||
Basic | 94,408 | 94,408 | 70,437 | 70,437 | ||||||||||||||||||||
Diluted | 94,408 | 94,408 | 70,502 | 70,502 | ||||||||||||||||||||
Net Income | $ | (584,317 | ) | $ | 89,256 | $ | (495,061 | ) | $ | 7,292 | $ | (974 | ) | $ | 6,318 | |||||||||
Other Comprehensive Loss | ||||||||||||||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||||||||||||||
Unrealized change in fair value net of ineffective portion | 24,410 | (24,410 | ) | — | (4,142 | ) | 4,142 | — | ||||||||||||||||
Effective portion reclassified to earnings during the period | (60,973 | ) | 60,973 | — | 3,622 | (3,622 | ) | — | ||||||||||||||||
Total Other Comprehensive Loss | (36,563 | ) | 36,563 | — | (520 | ) | 520 | — | ||||||||||||||||
Income Tax Expense (Benefit) | (12,797 | ) | 12,797 | — | (182 | ) | 182 | |||||||||||||||||
Net Other Comprehensive Loss | (23,766 | ) | 23,766 | — | (338 | ) | 338 | — | ||||||||||||||||
Comprehensive Income | $ | (608,083 | ) | $ | 113,022 | $ | (495,061 | ) | $ | 6,954 | $ | (636 | ) | $ | 6,318 |
275
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Nine Months Ended March 31, 2015 | Nine Months Ended March 31, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands, except share information) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | 925,676 | $ | (98,208 | ) | $ | 827,468 | $ | 801,414 | $ | 7,820 | $ | 809,234 | |||||||||||
Natural gas sales | 95,502 | (2,128 | ) | 93,374 | 105,177 | (3,893 | ) | 101,284 | ||||||||||||||||
Gain (loss) on derivative financial instruments | — | 265,150 | 265,150 | — | (58,703 | ) | (58,703 | ) | ||||||||||||||||
Total Revenues | 1,021,178 | 164,814 | 1,185,992 | 906,591 | (54,776 | ) | 851,815 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Depreciation, depletion and amortization | 528,773 | (6,531 | ) | 522,242 | 303,628 | (7,104 | ) | 296,524 | ||||||||||||||||
Impairment of oil and natural gas properties | 739,941 | (170,325 | ) | 569,616 | — | — | — | |||||||||||||||||
(Gain) loss on derivative financial instruments | 1,932 | (1,932 | ) | — | 6,958 | (6,958 | ) | — | ||||||||||||||||
All other costs and expenses | 848,776 | 4,169 | 852,945 | 370,271 | — | 370,271 | ||||||||||||||||||
Total Costs and Expenses | 2,119,422 | (174,619 | ) | 1,944,803 | 680,857 | (14,062 | ) | 666,795 | ||||||||||||||||
Operating Income | (1,098,244 | ) | 339,433 | (758,811 | ) | 225,734 | (40,714 | ) | 185,020 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Loss from equity method investees | (3,384 | ) | 433 | (2,951 | ) | (5,525 | ) | (405 | ) | (5,930 | ) | |||||||||||||
Other income, net | 3,173 | — | 3,173 | 2,302 | — | 2,302 | ||||||||||||||||||
Interest expense | (218,203 | ) | — | (218,203 | ) | (111,026 | ) | — | (111,026 | ) | ||||||||||||||
Total Other Expense, net | (218,414 | ) | 433 | (217,981 | ) | (114,249 | ) | (405 | ) | (114,654 | ) | |||||||||||||
Income Before Income Taxes | (1,316,658 | ) | 339,866 | (976,792 | ) | 111,485 | (41,119 | ) | 70,366 | |||||||||||||||
Income Tax Expense (Benefit) | (352,059 | ) | 119,101 | (232,958 | ) | 50,559 | (13,721 | ) | 36,838 | |||||||||||||||
Net Income | (964,599 | ) | 220,765 | (743,834 | ) | 60,926 | (27,398 | ) | 33,528 | |||||||||||||||
Preferred Stock Dividends | 8,605 | — | 8,605 | 8,617 | — | 8,617 | ||||||||||||||||||
Net Income Available for Common Stockholders | $ | (973,204 | ) | $ | 220,765 | $ | (752,439 | ) | $ | 52,309 | $ | (27,398 | ) | $ | 24,911 | |||||||||
Earnings per Share | ||||||||||||||||||||||||
Basic | $ | (10.34 | ) | $ | (8.00 | ) | $ | 0.71 | $ | 0.34 | ||||||||||||||
Diluted | $ | (10.34 | ) | $ | (8.00 | ) | $ | 0.71 | $ | 0.34 | ||||||||||||||
Weighted Average Number of Common Shares Outstanding | ||||||||||||||||||||||||
Basic | 94,076 | 94,076 | 73,415 | 73,415 | ||||||||||||||||||||
Diluted | 94,076 | 94,076 | 73,493 | 73,493 | ||||||||||||||||||||
Net Income | $ | (964,599 | ) | $ | 220,765 | $ | (743,834 | ) | $ | 60,926 | $ | (27,398 | ) | $ | 33,528 | |||||||||
Other Comprehensive Loss | ||||||||||||||||||||||||
Crude Oil and Natural Gas Cash Flow Hedges | ||||||||||||||||||||||||
Unrealized change in fair value net of ineffective portion | 277,010 | (277,010 | ) | — | (36,141 | ) | 36,141 | — | ||||||||||||||||
Effective portion reclassified to earnings during the period | (114,186 | ) | 114,186 | — | (12,083 | ) | 12,083 | — | ||||||||||||||||
Total Other Comprehensive Loss | 162,824 | (162,824 | ) | — | (48,224 | ) | 48,224 | — | ||||||||||||||||
Income Tax Expense (Benefit) | 56,988 | (56,988 | ) | — | (16,878 | ) | 16,878 | |||||||||||||||||
Net Other Comprehensive Loss | 105,836 | (105,836 | ) | — | (31,346 | ) | 31,346 | — | ||||||||||||||||
Comprehensive Income | $ | (858,763 | ) | $ | 114,929 | $ | (743,834 | ) | $ | 29,580 | $ | 3,948 | $ | 33,528 |
276
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 20 — Restatement of Previously Issued Consolidated Financial Statements – (continued)
Nine Months Ended March 31, 2015 | Nine Months Ended March 31, 2014 | |||||||||||||||||||||||
As Reported | Adjustment | Restated | As Reported | Adjustment | Restated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (964,599 | ) | $ | 220,765 | $ | (743,834 | ) | $ | 60,926 | $ | (27,398 | ) | $ | 33,528 | |||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | — | |||||||||||||||||||||||
Depreciation, depletion and amortization | 528,773 | (6,531 | ) | 522,242 | 303,628 | (7,104 | ) | 296,524 | ||||||||||||||||
Impairment of oil and natural gas properties | 739,941 | (170,325 | ) | 569,616 | — | — | ||||||||||||||||||
Goodwill impairment | 329,293 | — | 329,293 | — | — | — | ||||||||||||||||||
Deferred income tax expense (benefit) | (352,899 | ) | �� | 119,101 | (233,798 | ) | 47,197 | (13,722 | ) | 33,475 | ||||||||||||||
Change in fair value of derivative financial instruments | 77,876 | (162,962 | ) | (85,086 | ) | (549 | ) | 47,464 | 46,915 | |||||||||||||||
Accretion of asset retirement obligations | 37,723 | — | 37,723 | 20,817 | — | 20,817 | ||||||||||||||||||
Loss (income) from equity method investees | 3,384 | (433 | ) | 2,951 | 5,525 | 405 | 5,930 | |||||||||||||||||
Amortization and write-off of debt issuance costs and other | 17,942 | — | 17,942 | 9,715 | — | 9,715 | ||||||||||||||||||
Stock-based compensation | 3,271 | — | 3,271 | 5,292 | — | 5,292 | ||||||||||||||||||
Changes in operating assets and liabilities | — | — | ||||||||||||||||||||||
Accounts receivable | 62,163 | — | 62,163 | 20,551 | — | 20,551 | ||||||||||||||||||
Prepaid expenses and other current assets | 32,938 | — | 32,938 | 28,130 | — | 28,130 | ||||||||||||||||||
Settlement of asset retirement obligations | (77,235 | ) | — | (77,235 | ) | (46,269 | ) | — | (46,269 | ) | ||||||||||||||
Accounts payable and accrued liabilities | (278,239 | ) | 385 | (277,854 | ) | (9,047 | ) | 355 | (8,692 | ) | ||||||||||||||
Net Cash Provided by Operating Activities | 160,332 | — | 160,332 | 445,916 | — | 445,916 | ||||||||||||||||||
Net Cash Used in Investing Activities | (489,689 | ) | — | (489,689 | ) | (619,553 | ) | — | (619,553 | ) | ||||||||||||||
Net Cash Provided by Financing Activities | 785,575 | — | 785,575 | 477,339 | — | 477,339 | ||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents | 456,218 | — | 456,218 | 303,702 | — | 303,702 | ||||||||||||||||||
Cash and Cash Equivalents, beginning of period | 145,806 | 145,806 | — | — | ||||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 602,024 | $ | 602,024 | $ | 303,702 | $ | 303,702 |
277
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information
Our indirect, 100% wholly owned subsidiary, EGC, issued $650 million of its 6.875% Senior Notes due 2024 on May 27, 2014, $500 million of its 7.5% Senior Notes due 2021 on September 26, 2013, $750 million of its 9.25% Senior Notes due 2017 on December 17, 2010 and $250 million of its 7.75% Senior Notes due 2019 on February 25, 2011, each of which has been registered, or in the case of the 6.875% Senior Notes due 2024, will be registered. These notes are jointly, severally, fully and unconditionally guaranteed by the Bermuda parent company and each of EGC’s existing and future material domestic subsidiaries other than EPL and its subsidiaries, except that a guarantor can be automatically released and relieved of its obligations under certain customary circumstances contained in the above senior note indentures. These customary circumstances include: when a guarantor is declared “unrestricted” for covenant purposes, when the requirements for legal defeasance or covenant defeasance or to discharge the indenture have been satisfied, when the guarantor is sold or sells all of its assets or the guarantor no longer guarantees any obligations under EGC’s Revolving Credit Facility. When securities that are guaranteed are issued in a registered offering, Rule 3-10 of Regulation S-X of the SEC requires the issuer and guarantors to file separate financial statements. We meet the conditions in Rule 3-10 to report information about the assets, results of operations and comprehensive income (loss) and cash flows of the parent, subsidiary issuer and subsidiary guarantors using an alternative approach, which is to include in a footnote to our financial statements, condensed consolidating financial information for the same periods as those presented in our financial statements.
The information is presented using the equity method of accounting for investments in subsidiaries. Transactions between entities are presented on a gross basis in the Bermuda parent company, EGC, the guarantor subsidiaries, and non-guarantor subsidiaries columns with consolidating entries presented in the eliminations column. The principal consolidating entries eliminate investments in subsidiaries, intercompany balances and intercompany revenues and expenses. The following supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements and should be read in conjunction with our consolidated financial statements and notes thereto included in this Form 10-K.
278
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
March 31, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 48,383 | $ | 559,249 | $ | — | $ | — | $ | (5,608 | ) | $ | 602,024 | |||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 63,105 | 26,083 | (5,269 | ) | 83,919 | |||||||||||||||||
Joint interest billings | — | 1,949 | — | 14,263 | (36 | ) | 16,176 | |||||||||||||||||
Other | — | 18,914 | — | 6,822 | (492 | ) | 25,244 | |||||||||||||||||
Prepaid expenses and other current assets | 491 | 17,585 | — | 21,789 | (257 | ) | 39,608 | |||||||||||||||||
Deferred income taxes | — | — | — | 16,959 | — | 16,959 | ||||||||||||||||||
Derivative financial instruments | — | 49,916 | — | 2,906 | — | 52,822 | ||||||||||||||||||
Total Current Assets | 48,874 | 647,613 | 63,105 | 88,822 | (11,662 | ) | 836,752 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 2,347,151 | 2,396,442 | 1,108,240 | 5,851,833 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 22,759 | — | 22,759 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 2,347,151 | 2,419,201 | 1,108,240 | 5,874,592 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Derivative financial instruments | — | 9,767 | — | — | — | 9,767 | ||||||||||||||||||
Equity investments | 910,904 | 1,567,296 | — | 4,786,518 | (7,239,668 | ) | 25,050 | |||||||||||||||||
Intercompany receivables | 117,080 | 2,046,800 | — | — | (2,163,880 | ) | — | |||||||||||||||||
Restricted cash | — | — | — | 6,024 | — | 6,024 | ||||||||||||||||||
Deferred income taxes | — | 117,157 | — | 288,221 | (405,378 | ) | — | |||||||||||||||||
Other assets and debt issuance costs, net | 177,229 | 72,370 | 1 | 4,549 | (170,991 | ) | 83,158 | |||||||||||||||||
Total Other Assets | 1,205,213 | 3,813,390 | 1 | 5,085,312 | (9,979,917 | ) | 123,999 | |||||||||||||||||
Total Assets | $ | 1,254,087 | $ | 4,461,003 | $ | 2,410,257 | $ | 7,593,335 | $ | (8,883,339 | ) | $ | 6,835,343 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 43,149 | $ | 64,862 | $ | 96,001 | $ | (11,540 | ) | $ | 192,472 | |||||||||||
Accrued liabilities | 4,985 | 49,661 | 15,754 | 129,688 | (82,514 | ) | 117,574 | |||||||||||||||||
Notes payable | — | 4,949 | — | — | — | 4,949 | ||||||||||||||||||
Deferred income taxes | — | — | — | — | — | — | ||||||||||||||||||
Asset retirement obligations | — | — | 39,969 | 28,423 | — | 68,392 | ||||||||||||||||||
Current maturities of long-term debt | — | 13,285 | — | 3,997 | — | 17,282 | ||||||||||||||||||
Total Current Liabilities | 4,985 | 111,044 | 120,585 | 258,109 | (94,054 | ) | 400,669 | |||||||||||||||||
Long-term debt, less current maturities | 351,342 | 3,156,957 | — | 1,258,471 | (171,000 | ) | 4,595,770 | |||||||||||||||||
Deferred income taxes | 22,927 | 21,202 | — | 6,656 | 346,758 | 397,543 | ||||||||||||||||||
Asset retirement obligations | — | 50 | 247,677 | 221,306 | — | 469,033 | ||||||||||||||||||
Derivative financial instruments | — | 71 | — | — | — | 71 | ||||||||||||||||||
Intercompany payables | — | 21 | 1,845,823 | 385,694 | (2,231,538 | ) | — | |||||||||||||||||
Other liabilities | — | 5,331 | — | 2,837 | — | 8,168 | ||||||||||||||||||
Total Liabilities | 379,254 | 3,294,676 | 2,214,085 | 2,133,073 | (2,149,834 | ) | 5,871,254 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 471 | 1 | — | 12 | (13 | ) | 471 | |||||||||||||||||
Additional paid-in capital | 1,842,919 | 2,018,666 | 273,129 | 7,144,307 | (9,436,102 | ) | 1,842,919 | |||||||||||||||||
Accumulated earnings (deficit) | (968,558 | ) | (852,340 | ) | (76,957 | ) | (1,684,057 | ) | 2,702,610 | (879,302 | ) | |||||||||||||
Total Stockholders’ Equity | 874,833 | 1,166,327 | 196,172 | 5,460,262 | (6,733,505 | ) | 964,089 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 1,254,087 | $ | 4,461,003 | $ | 2,410,257 | $ | 7,593,335 | $ | (8,883,339 | ) | $ | 6,835,343 |
279
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING BALANCE SHEET
(Restated) (Unaudited)
June 30, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||
Current Assets | ||||||||||||||||||||||||
Cash and cash equivalents | $ | 135,703 | $ | 3,723 | $ | — | $ | 6,380 | $ | — | $ | 145,806 | ||||||||||||
Accounts receivable | ||||||||||||||||||||||||
Oil and natural gas sales | — | — | 127,773 | 50,990 | (11,688 | ) | 167,075 | |||||||||||||||||
Joint interest billings | — | 1,833 | — | 11,065 | — | 12,898 | ||||||||||||||||||
Other | 10 | 3,452 | 517 | 1,460 | (1 | ) | 5,438 | |||||||||||||||||
Prepaid expenses and other current assets | 230 | 27,705 | 350 | 44,245 | — | 72,530 | ||||||||||||||||||
Deferred income taxes | — | 27,424 | — | 25,163 | — | 52,587 | ||||||||||||||||||
Derivative financial instruments | — | 1,425 | — | — | — | 1,425 | ||||||||||||||||||
Total Current Assets | 135,943 | 65,562 | 128,640 | 139,303 | (11,689 | ) | 457,759 | |||||||||||||||||
Property and Equipment | ||||||||||||||||||||||||
Oil and natural gas properties, net | — | — | 3,227,584 | 3,197,765 | 1,914 | 6,427,263 | ||||||||||||||||||
Other property and equipment, net | — | — | — | 19,760 | — | 19,760 | ||||||||||||||||||
Total Property and Equipment, net | — | — | 3,227,584 | 3,217,525 | 1,914 | 6,447,023 | ||||||||||||||||||
Other Assets | ||||||||||||||||||||||||
Goodwill | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
Derivative financial instruments | — | 3,035 | — | — | — | 3,035 | ||||||||||||||||||
Equity investments | 1,681,640 | 2,871,756 | — | 2,291,045 | (6,803,798 | )) | 40,643 | |||||||||||||||||
Intercompany receivables | 102,489 | 1,627,931 | — | 80,983 | (1,811,403 | ) | — | |||||||||||||||||
Restricted cash | — | — | 325 | 6,025 | — | 6,350 | ||||||||||||||||||
Other assets and debt issuance costs, net | 178,299 | 42,155 | — | 7,940 | (171,000 | ) | 57,394 | |||||||||||||||||
Total Other Assets | 1,962,428 | 4,544,877 | 325 | 2,715,286 | (8,786,201 | ) | 436,715 | |||||||||||||||||
Total Assets | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 | |||||||||||
LIABILITIES | ||||||||||||||||||||||||
Current Liabilities | ||||||||||||||||||||||||
Accounts payable | $ | — | $ | 64,533 | $ | 150,909 | $ | 214,215 | $ | (11,881 | ) | $ | 417,776 | |||||||||||
Accrued liabilities | 1,640 | 12,501 | 28,750 | 154,587 | (63,952 | ) | 133,526 | |||||||||||||||||
Notes payable | — | 21,967 | — | — | — | 21,967 | ||||||||||||||||||
Deferred income taxes | 19,185 | — | — | — | (19,185 | ) | — | |||||||||||||||||
Asset retirement obligations | — | — | 39,819 | 39,830 | — | 79,649 | ||||||||||||||||||
Derivative financial instruments | — | 5,517 | — | 26,440 | — | 31,957 | ||||||||||||||||||
Current maturities of long-term debt | — | 14,093 | — | 927 | — | 15,020 | ||||||||||||||||||
Total Current Liabilities | 20,825 | 118,611 | 219,478 | 435,999 | (95,018 | ) | 699,895 | |||||||||||||||||
Long-term debt, less current maturities | 342,986 | 2,305,906 | — | 1,266,732 | (171,000 | ) | 3,744,624 | |||||||||||||||||
Deferred income taxes | — | 177,007 | — | 470,755 | 19,207 | 666,969 | ||||||||||||||||||
Asset retirement obligations | — | 49 | 247,272 | 232,864 | — | 480,185 | ||||||||||||||||||
Derivative financial instruments | — | 2,166 | — | 2,140 | — | 4,306 | ||||||||||||||||||
Intercompany payables | — | — | 1,640,094 | — | (1,640,094 | )) | — | |||||||||||||||||
Other liabilities | — | — | — | 10,958 | — | 10,958 | ||||||||||||||||||
Total Liabilities | 363,811 | 2,603,739 | 2,106,844 | 2,419,448 | (1,886,905 | ) | 5,606,937 | |||||||||||||||||
Stockholders’ Equity | ||||||||||||||||||||||||
Preferred stock | ||||||||||||||||||||||||
7.25% Convertible perpetual preferred stock | — | — | — | — | — | — | ||||||||||||||||||
5.625% Convertible perpetual preferred stock | 1 | — | — | — | — | 1 | ||||||||||||||||||
Common stock | 468 | 1 | 10 | (11 | ) | 468 | ||||||||||||||||||
Additional paid-in capital | 1,837,462 | 2,092,439 | 273,129 | 3,580,005 | (5,945,573 | ) | 1,837,462 | |||||||||||||||||
Accumulated earnings (deficit) | (103,371 | ) | (85,740 | ) | 976,576 | 72,651 | (963,487 | ) | (103,371 | ) | ||||||||||||||
Total Stockholders’ Equity | 1,734,560 | 2,006,700 | 1,249,705 | 3,652,666 | (6,909,071 | ) | 1,734,560 | |||||||||||||||||
Total Liabilities and Stockholders’ Equity | $ | 2,098,371 | $ | 4,610,439 | $ | 3,356,549 | $ | 6,072,114 | $ | (8,795,976 | ) | $ | 7,341,497 |
280
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended March 31, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 102,147 | $ | 77,444 | $ | (1,986 | ) | $ | 177,605 | |||||||||||
Natural gas sales | — | — | 14,812 | 12,200 | — | 27,012 | ||||||||||||||||||
Gain (loss) on derivative financial instruments | — | 19,176 | — | (2,213 | ) | — | 16,963 | |||||||||||||||||
Total Revenues | — | 19,176 | 116,959 | 87,431 | (1,986 | ) | 221,580 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (401 | ) | 57,943 | 50,513 | 55 | 108,110 | |||||||||||||||||
Production taxes | — | 9 | 624 | 904 | — | 1,537 | ||||||||||||||||||
Gathering and transportation | — | — | 3,726 | — | — | 3,726 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 104,824 | 75,866 | 7,257 | 187,947 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 6,537 | 5,569 | — | 12,106 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | 700,195 | 300,280 | (430,859 | ) | 569,616 | |||||||||||||||||
General and administrative expense | 1,246 | 5,285 | 15,897 | 14,693 | — | 37,121 | ||||||||||||||||||
Total Costs and Expenses | 1,246 | 4,893 | 889,746 | 447,825 | (423,547 | ) | 920,163 | |||||||||||||||||
Operating Income (Loss) | (1,246 | ) | 14,283 | (772,787 | ) | (360,394 | ) | 421,561 | (698,583 | ) | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | (464,671 | ) | (720,028 | ) | — | (670,077 | ) | 1,852,141 | (2,635 | ) | ||||||||||||||
Other income (expense) – net | 5,085 | 5,220 | — | 4,437 | (13,511 | ) | 1,231 | |||||||||||||||||
Interest expense | (6,111 | ) | (70,832 | ) | — | (21,607 | ) | 13,511 | (85,039 | ) | ||||||||||||||
Total Other Expense | (465,697 | ) | (785,640 | ) | — | (687,247 | ) | 1,852,141 | (86,443 | ) | ||||||||||||||
Income (Loss) Before Income Taxes | (466,943 | ) | (771,357 | ) | (772,787 | ) | (1,047,641 | ) | 2,273,702 | (785,026 | ) | |||||||||||||
Income Tax Expense (Benefit) | 1,513 | (219,764 | ) | — | (823,851 | ) | 752,137 | (289,965 | ) | |||||||||||||||
Net Income (Loss) | (468,456 | ) | (551,593 | ) | (772,787 | ) | (223,790 | ) | 1,521,565 | (495,061 | ) | |||||||||||||
Preferred Stock Dividends | 2,862 | — | — | — | — | 2,862 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (471,318 | ) | $ | (551,593 | ) | $ | (772,787 | ) | $ | (223,790 | ) | $ | 1,521,565 | $ | (497,923 | ) |
281
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Three Months Ended March 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 254,641 | $ | — | $ | — | $ | 254,641 | ||||||||||||
Natural gas sales | — | — | 37,562 | — | — | 37,562 | ||||||||||||||||||
Loss on derivative financial instruments | — | (7,349 | ) | — | — | — | (7,349 | ) | ||||||||||||||||
Total Revenues | — | (7,349 | ) | 292,203 | — | — | 284,854 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (94 | ) | 83,718 | — | — | 83,624 | |||||||||||||||||
Production taxes | — | 11 | 1,079 | — | — | 1,090 | ||||||||||||||||||
Gathering and transportation | — | — | 5,700 | — | — | 5,700 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 96,837 | 871 | — | 97,708 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 6,066 | — | — | 6,066 | ||||||||||||||||||
General and administrative expense | 1,218 | 354 | 19,878 | 2,758 | — | 24,208 | ||||||||||||||||||
Total Costs and Expenses | 1,218 | 271 | 213,278 | 3,629 | — | 218,396 | ||||||||||||||||||
Operating Income (Loss) | (1,218 | ) | (7,620 | ) | 78,925 | (3,629 | ) | — | 66,458 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 9,348 | 121,599 | — | 130,140 | (262,184 | ) | (1,097 | ) | ||||||||||||||||
Other income (expense) – net | 4,950 | 499 | — | (63,709 | ) | 59,127 | 867 | |||||||||||||||||
Interest expense | (6,522 | ) | (34,589 | ) | (1,505 | ) | (9,057 | ) | 8,973 | (42,700 | ) | |||||||||||||
Total Other Income (Expense) | 7,776 | 87,509 | (1,505 | ) | 57,374 | (194,084 | ) | (42,930 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 6,558 | 79,889 | 77,420 | 53,745 | (194,084 | ) | 23,528 | |||||||||||||||||
Income Tax Expense (Benefit) | 1,293 | 14,757 | — | 1,160 | — | 17,210 | ||||||||||||||||||
Net Income (Loss) | 5,265 | 65,132 | 77,420 | 52,585 | (194,084 | ) | 6,318 | |||||||||||||||||
Preferred Stock Dividends | 2,872 | — | — | — | — | 2,872 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | 2,393 | $ | 65,132 | $ | 77,420 | $ | 52,585 | $ | (194,084 | ) | $ | 3,446 |
282
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Nine Months Ended March 31, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 472,870 | $ | 356,584 | $ | (1,986 | ) | $ | 827,468 | |||||||||||
Natural gas sales | — | — | 54,672 | 38,702 | — | 93,374 | ||||||||||||||||||
Gain on derivative financial instruments | — | 223,270 | — | 41,880 | — | 265,150 | ||||||||||||||||||
Total Revenues | — | 223,270 | 527,542 | 437,166 | (1,986 | ) | 1,185,992 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (401 | ) | 206,517 | 163,890 | 55 | 370,061 | |||||||||||||||||
Production taxes | — | 25 | 2,702 | 4,166 | — | 6,893 | ||||||||||||||||||
Gathering and transportation | — | — | 17,685 | — | — | 17,685 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 294,349 | 239,710 | (11,817 | ) | 522,242 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 19,875 | 17,848 | — | 37,723 | ||||||||||||||||||
Impairment of oil and natural gas properties | — | — | 700,195 | 963,986 | (1,094,565 | ) | 569,616 | |||||||||||||||||
Goodwill impairment | — | — | — | 329,293 | — | 329,293 | ||||||||||||||||||
General and administrative expense | 4,741 | 8,995 | 46,162 | 31,392 | — | 91,290 | ||||||||||||||||||
Total Costs and Expenses | 4,741 | 8,619 | 1,287,485 | 1,750,285 | (1,106,327 | ) | 1,944,803 | |||||||||||||||||
Operating Income (Loss) | (4,741 | ) | 214,651 | (759,943 | ) | (1,313,119 | ) | 1,104,341 | (758,811 | ) | ||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | (712,318 | ) | (1,015,750 | ) | — | (1,028,736 | ) | 2,753,853 | (2,951 | ) | ||||||||||||||
Other income (expense) – net | 15,401 | 6,189 | — | 13,397 | (31,814 | ) | 3,173 | |||||||||||||||||
Interest expense | (18,432 | ) | (166,758 | ) | (2,914 | ) | (61,913 | ) | 31,814 | (218,203 | ) | |||||||||||||
Total Other Expense | (715,349 | ) | (1,176,319 | ) | (2,914 | ) | (1,077,252 | ) | 2,753,853 | (217,981 | ) | |||||||||||||
Income (Loss) Before Income Taxes | (720,090 | ) | (961,668 | ) | (762,857 | ) | (2,390,371 | ) | 3,858,194 | (976,792 | ) | |||||||||||||
Income Tax Expense (Benefit) | 4,582 | (175,377 | ) | — | (814,300 | ) | 752,137 | (232,958 | ) | |||||||||||||||
Net Income (Loss) | (724,672 | ) | (786,291 | ) | (762,857 | ) | (1,576,071 | ) | 3,106,057 | (743,834 | ) | |||||||||||||
Preferred Stock Dividends | 8,605 | — | — | — | — | 8,605 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | (733,277 | ) | $ | (786,291 | ) | $ | (762,857 | ) | $ | (1,576,071 | ) | $ | 3,106,057 | $ | (752,439 | ) |
283
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
(Restated) (Unaudited)
For the Nine Months Ended March 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||
Revenues | ||||||||||||||||||||||||
Crude oil sales | $ | — | $ | — | $ | 809,234 | $ | — | $ | — | $ | 809,234 | ||||||||||||
Natural gas sales | — | — | 101,284 | — | — | 101,284 | ||||||||||||||||||
Loss on derivative financial instruments | — | (58,703 | ) | — | — | — | (58,703 | ) | ||||||||||||||||
Total Revenues | — | (58,703 | ) | 910,518 | — | — | 851,815 | |||||||||||||||||
Costs and Expenses | ||||||||||||||||||||||||
Lease operating | — | (950 | ) | 264,126 | — | — | 263,176 | |||||||||||||||||
Production taxes | — | 38 | 3,639 | — | — | 3,677 | ||||||||||||||||||
Gathering and transportation | — | — | 17,023 | — | — | 17,023 | ||||||||||||||||||
Depreciation, depletion and amortization | — | — | 293,897 | 2,627 | — | 296,524 | ||||||||||||||||||
Accretion of asset retirement obligations | — | — | 20,817 | — | — | 20,817 | ||||||||||||||||||
General and administrative expense | 4,106 | 671 | 56,053 | 4,748 | — | 65,578 | ||||||||||||||||||
Total Costs and Expenses | 4,106 | (241 | ) | 655,555 | 7,375 | — | 666,795 | |||||||||||||||||
Operating Income (Loss) | (4,106 | ) | (58,462 | ) | 254,963 | (7,375 | ) | — | 185,020 | |||||||||||||||
Other Income (Expense) | ||||||||||||||||||||||||
Income from equity method investees | 35,465 | 290,688 | — | 123,302 | (455,385 | ) | (5,930 | ) | ||||||||||||||||
Other income (expense) – net | 14,783 | 1,469 | — | 13,366 | (27,316 | ) | 2,302 | |||||||||||||||||
Interest expense | (9,252 | ) | (96,998 | ) | (4,537 | ) | (27,555 | ) | 27,316 | (111,026 | ) | |||||||||||||
Total Other Income (Expense) | 40,996 | 195,159 | (4,537 | ) | 109,113 | (455,385 | ) | (114,654 | ) | |||||||||||||||
Income (Loss) Before Income Taxes | 36,890 | 136,697 | 250,426 | 101,738 | (455,385 | ) | 70,366 | |||||||||||||||||
Income Tax Expense (Benefit) | 4,415 | 34,458 | (2,035 | ) | — | 36,838 | ||||||||||||||||||
Net Income (Loss) | 32,475 | 102,239 | 250,426 | 103,773 | (455,385 | ) | 33,528 | |||||||||||||||||
Preferred Stock Dividends | 8,617 | — | — | — | — | 8,617 | ||||||||||||||||||
Net Income (Loss) Available for Common Stockholders | $ | 23,858 | $ | 102,239 | $ | 250,426 | $ | 103,773 | $ | (455,385 | ) | $ | 24,911 |
284
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Nine Months Ended March 31, 2015 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | (724,672 | ) | $ | (786,291 | ) | $ | (762,857 | ) | $ | (1,576,071 | ) | $ | 3,106,057 | $ | (743,834 | ) | |||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 294,349 | 239,710 | (11,817 | ) | 522,242 | |||||||||||||||||
Impairment of oil and natural gas properties | — | — | 700,195 | 963,986 | (1,094,565 | ) | 569,616 | |||||||||||||||||
Goodwill impairment | — | — | — | 329,293 | ��� | 329,293 | ||||||||||||||||||
Deferred income tax expense | 3,742 | (174,202 | ) | — | (815,474 | ) | 752,136 | (233,798 | ) | |||||||||||||||
Change in fair value of derivative financial instruments | — | (72,043 | ) | — | (13,043 | ) | — | (85,086 | ) | |||||||||||||||
Accretion of asset retirement obligations | — | — | 19,875 | 17,848 | — | 37,723 | ||||||||||||||||||
Loss from equity method investees | 712,318 | 1,015,750 | — | 1,028,736 | (2,753,853 | ) | 2,951 | |||||||||||||||||
Amortization and write-off of debt issuance costs and other | 9,426 | 16,173 | — | (7,657 | ) | — | 17,942 | |||||||||||||||||
Stock-based compensation | 3,271 | — | — | — | — | 3,271 | ||||||||||||||||||
Changes in operating assets and liabilities | — | |||||||||||||||||||||||
Accounts receivable | 9 | (17,130 | ) | 65,712 | 13,456 | 116 | 62,163 | |||||||||||||||||
Prepaid expenses and other current assets | (261 | ) | 10,120 | 607 | 22,472 | — | 32,938 | |||||||||||||||||
Settlement of asset retirement obligations | — | — | (38,211 | ) | (39,024 | ) | — | (77,235 | ) | |||||||||||||||
Accounts payable and accrued liabilities | (11,243 | ) | (300,401 | 9,527 | 69,476 | (45,213 | ) | (277,854 | ) | |||||||||||||||
Net Cash Provided by (Used in) Operating Activities | (7,410 | ) | (308,024 | ) | 289,197 | 233,708 | (47,139 | ) | 160,332 | |||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (301 | ) | — | — | (301 | ) | ||||||||||||||||
Capital expenditures | — | (171 | ) | (104,383 | ) | (407,748 | ) | — | (512,302 | ) | ||||||||||||||
Insurance payments received | — | — | 2,600 | 69 | — | 2,669 | ||||||||||||||||||
Change in equity method investments | — | — | — | 12,642 | — | 12,642 | ||||||||||||||||||
Intercompany investment | (50,000 | ) | 50,000 | — | 153,000 | (153,000 | ) | — | ||||||||||||||||
Transfers from restricted cash | — | — | 325 | — | — | 325 | ||||||||||||||||||
Proceeds from the sale of properties | — | — | 7,093 | — | — | 7,093 | ||||||||||||||||||
Other | — | — | — | 185 | — | 185 | ||||||||||||||||||
Net Cash (Used in) Investing Activities | (50,000 | ) | 49,829 | (94,666 | ) | (241,852 | ) | (153,000 | ) | (489,689 | ) | |||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,187 | — | — | — | — | 2,187 | ||||||||||||||||||
Dividends to shareholders – common | (23,492 | ) | — | (194,531 | ) | — | 194,531 | (23,492 | ) | |||||||||||||||
Dividends to shareholders – preferred | (8,605 | ) | — | — | — | — | (8,605 | ) | ||||||||||||||||
Proceeds from long-term debt | — | 2,261,572 | — | 325,000 | — | 2,586,572 | ||||||||||||||||||
Payments on long-term debt | — | (1,407,209 | ) | — | (322,146 | ) | — | (1,729,355 | ) | |||||||||||||||
Debt issuance costs | — | (40,642 | ) | — | (1,090 | ) | — | (41,732 | ) | |||||||||||||||
Net Cash Provided by (Used in) Financing Activities | (29,910 | ) | 813,721 | (194,531 | ) | 1,764 | 194,531 | 785,575 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | (87,320 | ) | 555,526 | — | (6,380 | ) | (5,608 | ) | 456,218 | |||||||||||||||
Cash and Cash Equivalents, beginning of period | 135,703 | 3,723 | — | 6,380 | — | 145,806 | ||||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 48,383 | $ | 559,249 | $ | — | $ | — | $ | (5,608 | ) | $ | 602,024 |
285
ENERGY XXI LTD
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTHS ENDED MARCH 31, 2015
(Unaudited)
Note 21 — Supplemental Guarantor Information – (continued)
ENERGY XXI LTD
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
(Restated) (Unaudited)
For the Nine Months Ended March 31, 2014 | ||||||||||||||||||||||||
EXXI Bermuda Parent | EGC Issuer | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Reclassifications & Eliminations | Consolidated | |||||||||||||||||||
(In Thousands) | ||||||||||||||||||||||||
Cash Flows From Operating Activities | ||||||||||||||||||||||||
Net income (loss) | $ | 32,475 | $ | 102,239 | $ | 250,426 | $ | 103,773 | $ | (455,385 | ) | $ | 33,528 | |||||||||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | ||||||||||||||||||||||||
Depreciation, depletion and amortization | — | — | 293,897 | 2,627 | — | 296,524 | ||||||||||||||||||
Deferred income tax expense | (16,883 | ) | (38,952 | ) | — | 89,310 | — | 33,475 | ||||||||||||||||
Change in fair value of derivative financial instruments | — | 67,984 | — | (21,069 | ) | — | 46,915 | |||||||||||||||||
Accretion of asset retirement obligations | — | — | 20,817 | — | — | 20,817 | ||||||||||||||||||
Loss from equity method investees | (35,465 | ) | (290,688 | ) | — | (123,302 | ) | 455,385 | 5,930 | |||||||||||||||
Amortization and write-off of debt issuance costs and other | 4,985 | 4,698 | — | 32 | — | 9,715 | ||||||||||||||||||
Stock-based compensation | 5,292 | — | — | — | — | 5,292 | ||||||||||||||||||
Changes in operating assets and liabilities | ||||||||||||||||||||||||
Accounts receivable | — | 233,460 | 3,453 | (1,006 | ) | (215,356 | ) | 20,551 | ||||||||||||||||
Prepaid expenses and other current assets | (194 | ) | 26,971 | (331 | ) | 1,684 | — | 28,130 | ||||||||||||||||
Settlement of asset retirement obligations | — | — | (46,269 | ) | — | — | (46,269 | ) | ||||||||||||||||
Accounts payable and accrued liabilities | (6,520 | ) | (435,873 | ) | 253,553 | (36,679 | ) | 216,827 | (8,692 | ) | ||||||||||||||
Net Cash Provided by (Used in) Operating Activities | (16,310 | ) | (330,161 | ) | 775,546 | 15,370 | 1,471 | 445,916 | ||||||||||||||||
Cash Flows from Investing Activities | ||||||||||||||||||||||||
Acquisitions, net of cash acquired | — | — | (35,082 | ) | — | — | (35,082 | ) | ||||||||||||||||
Capital expenditures | — | 16,618 | (589,018 | ) | (2,424 | ) | — | (574,824 | ) | |||||||||||||||
Change in equity method investments | — | — | — | (11,694 | ) | — | (11,694 | ) | ||||||||||||||||
Transfers to restricted cash | — | — | (325 | ) | — | — | (325 | ) | ||||||||||||||||
Proceeds from the sale of properties | — | — | 1,748 | — | — | 1,748 | ||||||||||||||||||
Other | — | — | 570 | 54 | — | 624 | ||||||||||||||||||
Net Cash Used in (Provided by) Investing Activities | — | 16,618 | (622,107 | ) | (14,064 | ) | — | (619,553 | ) | |||||||||||||||
Cash Flows from Financing Activities | ||||||||||||||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 3,844 | — | — | — | — | 3,844 | ||||||||||||||||||
Proceeds from convertible debt allocated to additional paid-in capital | 63,432 | — | — | — | — | 63,432 | ||||||||||||||||||
Repurchase of company common stock | (30,824 | ) | — | (153,439 | ) | — | — | (184,263 | ) | |||||||||||||||
Dividends to shareholders – common | (26,238 | ) | — | — | — | — | (26,238 | ) | ||||||||||||||||
Dividends to shareholders – preferred | (8,617 | ) | — | — | — | — | (8,617 | ) | ||||||||||||||||
Proceeds from long-term debt | 336,568 | 1,703,191 | — | — | — | 2,039,759 | ||||||||||||||||||
Payments on long-term debt | — | (1,391,068 | ) | — | (311 | ) | — | (1,391,379 | ) | |||||||||||||||
Debt issuance costs | (9,364 | ) | (9,835 | ) | — | — | — | (19,199 | ) | |||||||||||||||
Net Cash Provided by (Used in) Financing Activities | 328,801 | 302,288 | (153,439 | ) | (311 | ) | — | 477,339 | ||||||||||||||||
Net Decrease in Cash and Cash Equivalents | 312,491 | (11,255 | ) | — | 995 | 1,471 | 303,702 | |||||||||||||||||
Cash and Cash Equivalents, beginning of period | 1,334 | — | — | 137 | (1,471 | ) | — | |||||||||||||||||
Cash and Cash Equivalents, end of period | $ | 313,825 | $ | (11,255 | ) | $ | — | $ | 1,132 | $ | — | $ | 303,702 |
286
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
As previously reported in our Current Report on Form 8-K filed on December 4, 2014, on December 1, 2014, UHY LLP (“UHY”) informed the Company that its Texas practice had been acquired by BDO USA, LLP (“BDO”). As a result of this transaction, UHY resigned, effective as of December 1, 2014 (the “Resignation Date”), as the Company’s independent registered public accounting firm for the fiscal year ending June 30, 2015. UHY had served as the independent registered public accounting firm of Energy XXI Ltd for the fiscal year ended June 30, 2014. The Audit Committee of the Board of Directors of the Company (the “Audit Committee”) had selected UHY to serve as the Company’s independent registered public accounting firm for the fiscal year ending June 30, 2015. In addition, the shareholders of the Company approved and ratified that appointment at the Company’s Annual General Meeting on November 14, 2014.
During the Company’s two most recent fiscal years, UHY’s audit reports on the Company’s consolidated financial statements did not contain an adverse opinion or disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.
During the Company’s two most recent fiscal years and the subsequent interim period through the Resignation Date, the Company and UHY did not have any disagreements on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure which, if not resolved to the satisfaction of UHY, would have caused UHY to make reference to the matter in its reports on the Company’s consolidated financial statements during such periods; and there were no “reportable events” as the term is described in Item 304(a)(1)(v) of Regulation S-K.
The Company requested UHY furnish a letter addressed to the Securities and Exchange Commission, pursuant to Item 304(a)(3) of Regulation S-K, stating whether or not UHY agrees with the above statements, which letter we filed as Exhibit 16.1 to our Current Report on Form 8-K filed on December 4, 2014.
The Audit Committee recommended and approved the engagement of BDO as the successor independent registered public accounting firm, effective upon the consummation of the merger on the Resignation Date. At no time during the Company’s fiscal years ended June 30, 2014 and 2013 and during any subsequent interim period through the Resignation Date, did the Company consult with BDO regarding (i) the application of accounting principles to a specific completed or contemplated transaction, or the type of audit opinion that might be rendered on the Company’s financial statements, and no written report or oral advice was provided to the Company that BDO concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue or (ii) any matter that was the subject of a disagreement as defined in Item 304(a)(1)(iv) and related instructions of Regulation S-K or a “reportable event” as described in Item 304(a)(1)(v) of Regulation S-K.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including our principal executive officer and our principal financial officer, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) to the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. As described in Management’s Report on Internal Control over Financial Reporting included in Item 8 “Financial Statements and Supplementary Data” of this Form 10-K, we identified material weaknesses in the Company’s internal control over financial reporting (as defined in the Exchange Act). As a result of these material weaknesses, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective as of the end of the period covered by this Form 10-K.
287
As described in Management’s Report on Internal Control over Financial Reporting included in Item 8 “Financial Statements and Supplementary Data” of this Form 10-K, we did not maintain properly designed controls over the contemporaneous formal documentation that we had historically prepared to support our initial designations of derivative financial instruments as cash flow hedges in connection with our crude oil and natural gas hedging program. Specifically, the controls in place relating to the documentation of hedge designations were not properly designed to provide reasonable assurance that these derivative contracts would be properly recorded and disclosed in the financial statements in accordance with U.S. GAAP. As a result, our controls failed to detect that our formal hedge documentation did not meet the technical requirements to qualify for cash flow hedge accounting treatment in accordance with ASC Topic 815,Derivatives and Hedging. The primary reason for this determination was that the formal hedge documentation lacked specificity of the hedged items and, therefore, the designations failed to meet hedge documentation requirements for cash flow hedge accounting treatment. Effective June 30, 2015, management discontinued the use of hedge accounting on all derivative contracts and does not expect the material weakness associated with hedge accounting to recur. If, in the future, we were to begin to designate our derivatives as hedges we would need to enhance our controls regarding consideration of all sources of ineffectiveness.
In light of this material weakness, in preparing our financial statements as of and for the fiscal year ended June 30, 2015, we performed additional analyses and procedures pertaining to our accounting for derivative instruments to ensure that our consolidated financial statements included in this Form 10-K have been prepared in accordance with U.S. GAAP and determined that it was necessary to restate (1) our consolidated balance sheet as of June 30, 2014, (2) our consolidated statements of operations, consolidated statements of cash flows, and consolidated statements of stockholders’ equity (deficit) for the years ended June 30, 2014 and 2013, (3) our quarterly consolidated financial statements for the quarters ended September 30, 2014 and 2013, December 31, 2014 and 2013, March 31, 2015 and 2014, (4) our quarterly consolidated financial information for the quarter ended June 30, 2014, and (5) our selected financial data for the years ended June 30, 2014, 2013, 2012, and 2011. Detailed disclosures concerning this restatement are included in our consolidated financial statements.
In addition, the Board has recently learned that, in 2007, 2009 and 2014, the Company’s Chief Executive Officer borrowed funds from personal acquaintances or their affiliates, certain of whom provided the Company with services. The Board also learned that Norman Louie, one of our directors, made a personal loan to Mr. Schiller in 2014 before Mr. Louie became a director of the Company. At the time the loan was made, Mr. Louie was a managing director at Mount Kellett Capital Management LP, which at the time, and as of June 30, 2015, owned a majority interest in Energy XXI M21K and 6.3% of the Company’s common stock. The loans made in 2014 are still outstanding. Since Mr. Schiller did not disclose the personal loans before they were made, the Board has determined that he did not comply with the procedural requirements of the Company’s Code of Business Conduct and Ethics. Upon learning of Mr. Schiller’s personal loans from affiliates of service providers, the Board engaged independent legal counsel to conduct an internal investigation, with the assistance of outside forensic accountants, to review these loans and the Company’s vendor procurement processes. The Board is still reviewing the results of the internal investigation. Although the internal investigation has not uncovered any illegal activity or any impact on the Company’s financial reporting or financial statements, the Company concluded this non-compliance to be a material weakness in its control environment given the leadership position of this officer, the visibility and importance of his actions to the Company’s overall system of controls and the significance with which the Company views this nondisclosure. As part of its review, the Board has begun the process of designing and implementing additional controls and procedures, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise from Mr. Schiller’s personal loans; revising the Code of Business Conduct and Ethics to explicitly ban any such personal loans in the future; and implementing an enhanced comprehensive training program on the Company’s Code of Business Conduct and Ethics.
Management’s Annual Report on Internal Control over Financial Reporting
Management’s Report on Internal Control over Financial Reporting is included in Item 8 “Financial Statements and Supplementary Data” of this Form 10-K on page 87 and is incorporated herein by reference.
288
Changes in Internal Control over Financial Reporting
Effective June 3, 2014, the Company acquired EPL. During the quarterly period ended June 30, 2015, changes to the Company’s controls occurred as substantially all of EPL’s stand-alone financial systems and processes used to record financial data were replaced and the associated financial data was converted onto the Company’s systems and processes. Therefore, EPL’s controls have been aligned and integrated into the Company’s control environment and the Company has included EPL in its assessment of the effectiveness of internal control over financial reporting as of June 30, 2015.
In addition, the Board has begun the process of designing and implementing additional controls and procedures in response to a material weakness in its control environment as discussed above, including, but not limited to, strengthening the Company’s vendor procurement procedures to address any potential conflicts of interest that could arise from Mr. Schiller’s personal loans; revising the Code of Business Conduct and Ethics to explicitly ban any such personal loans in the future; and implementing an enhanced comprehensive training program on the Company’s Code of Business Conduct and Ethics.
Other than the changes noted above, there was no change in our system of internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our quarterly period ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
We have adopted a Code of Business Conduct and Ethics, which covers a wide range of business practices and procedures. The Code of Business Conduct and Ethics also represents the code of ethics applicable to our principal executive officer, principal financial officer, and principal accounting officer or controller and persons performing similar functions (“senior financial officers”). A copy of the Code of Business Conduct and Ethics is available on our websitewww.energyxxi.com under “Management Team — Corporate Governance.” We intend to disclose any amendments to or waivers of the Code of Business Conduct and Ethics on behalf of our senior financial officers on our websitewww.energyxxi.com under “Investor Relations” and “Corporate Governance” promptly following the date of the amendment or waiver.
Pursuant to general instruction G to Form 10-K, the remaining information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 11. Executive Compensation
Pursuant to general instruction G to Form 10-K, the information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to general instruction G to Form 10-K, the information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to general instruction G to Form 10-K, the information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
289
Item 14. Principal Accountant Fees and Services
Pursuant to general instruction G to Form 10-K, the information required by this Item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Form 10-K.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as a part of this Form 10-K or incorporated by reference:
(1) Financial Statements
(2) Financial Statement Schedules
The restricted net assets of consolidated subsidiaries exceed 25% of our consolidated net assets, accordingly below is the schedule of parent-only financial statements as prescribed by Rule 12-04 of Regulation S-X. All other schedules are omitted because they are either not applicable or required information is shown in the consolidated financial statements or notes thereto.
290
ENERGY XXI LTD
CONDENSED BALANCE SHEETS
(In Thousands)
June 30, | ||||||||
2015 | 2014 (Restated) | |||||||
ASSETS | ||||||||
Current assets | $ | 37,955 | $ | 135,943 | ||||
Intercompany receivable | 122,039 | 102,489 | ||||||
Equity investments | — | 1,681,640 | ||||||
Intercompany notes receivable | 171,000 | 171,000 | ||||||
Other assets and debt issuance costs, net of accumulated amortization | 5,861 | 7,299 | ||||||
Total Assets | $ | 336,855 | $ | 2,098,371 | ||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
Current liabilities | 25,150 | 20,825 | ||||||
Accumulated losses in excess of equity investments | 686,209 | — | ||||||
Long-term debt | 354,218 | 342,986 | ||||||
Stockholders’ equity (deficit) | (728,722 | ) | 1,734,560 | |||||
Total Liabilities and Stockholders’ Equity (Deficit) | $ | 336,855 | $ | 2,098,371 |
See accompanying Notes to Condensed Financial Statements
291
ENERGY XXI LTD
CONDENSED STATEMENT OF OPERATIONS
(In Thousands)
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Operating Expenses | ||||||||||||
General and administrative expense | $ | 8,409 | $ | 7,380 | $ | 7,439 | ||||||
Operating Loss | 8,409 | 7,380 | 7,439 | |||||||||
Other Income (Expense) | ||||||||||||
Income (loss) from equity method investees | (2,415,367 | ) | 26,009 | 175,218 | ||||||||
Interest income | 16,798 | 16,788 | 16,679 | |||||||||
Interest expense | (24,669 | ) | (14,485 | ) | — | |||||||
Guarantee income | 3,732 | 3,135 | 1,900 | |||||||||
Total Other Income (Loss) | (2,419,506 | ) | 31,447 | 193,797 | ||||||||
Income (Loss) Before Income Taxes | (2,427,915 | ) | 24,067 | 186,358 | ||||||||
Income Tax Expense | 5,923 | 5,942 | 5,575 | |||||||||
Net Income (Loss) | $ | (2,433,838 | ) | $ | 18,125 | $ | 180,783 |
See accompanying Notes to Condensed Financial Statements
292
ENERGY XXI LTD
CONDENSED STATEMENTS OF CASH FLOWS
(In Thousands)
Year Ended June 30, | ||||||||||||
2015 | 2014 (Restated) | 2013 (Restated) | ||||||||||
Cash Flows From Operating Activities | ||||||||||||
Net income (loss) | $ | (2,433,838 | ) | $ | 18,125 | $ | 180,783 | |||||
Adjustments to reconcile net income to net cash provided by | ||||||||||||
(used in) operating activities: | ||||||||||||
Stock-based compensation and deferred income tax expense | 9,113 | 9,013 | (3,793 | ) | ||||||||
Amortization of debt issuance costs and other | 12,670 | 7,219 | — | |||||||||
Income from equity method investees | 2,415,367 | (26,009 | ) | (175,218 | ) | |||||||
Changes in operating assets and liabilities | (18,392 | ) | (5,880 | ) | 24,209 | |||||||
Net Cash Provided by (Used in) Operating Activities | (15,080 | ) | 2,468 | 25,981 | ||||||||
Cash Flows from Investing Activities | ||||||||||||
Change in equity method investments | (50,000 | ) | (185,568 | ) | (4,010 | ) | ||||||
Net Cash Used in Investing Activities | (50,000 | ) | (185,568 | ) | (4,010 | ) | ||||||
Cash Flows from Financing Activities | ||||||||||||
Proceeds from the issuance of common and preferred stock, net of offering costs | 2,336 | 3,994 | 7,021 | |||||||||
Repurchase of company common stock | — | (30,824 | ) | — | ||||||||
Dividends to shareholders | (35,904 | ) | (46,169 | ) | (37,488 | ) | ||||||
Debt issuance costs | — | (9,585 | ) | — | ||||||||
Proceeds from convertible debt allocated to additional paid-in capital | — | 63,432 | — | |||||||||
Proceeds from long-term debt | — | 336,568 | — | |||||||||
Other | (2 | ) | 53 | — | ||||||||
Net Cash Provided by (Used in) Financing Activities | (33,570 | ) | 317,469 | (30,467 | ) | |||||||
Net Increase (Decrease) in Cash and Cash Equivalents | (98,650 | ) | 134,369 | (8,496 | ) | |||||||
Cash and Cash Equivalents, beginning of year | 135,703 | 1,334 | 9,830 | |||||||||
Cash and Cash Equivalents, end of year | $ | 37,053 | $ | 135,703 | $ | 1,334 |
See accompanying Notes to Condensed Financial Statements
293
ENERGY XXI LTD
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note 1 — Basis of Presentation
These condensed parent only financial statements of Energy XXI Ltd (the “Company”) do not include all of the information and notes normally included with financial statements prepared in accordance with U.S. GAAP and therefore, should be read in conjunction with the consolidated financial statements and notes thereto of the Company, included in this Annual Report on Form 10-K. The Company’s investments in its wholly-owned subsidiaries are accounted for under the equity method.
Energy XXI Gulf Coast, Inc.’s (“EGC”) credit agreement restricts the ability of EGC to make any dividend or other distributions to the Company, subject to certain exceptions. As of June 30, 2015, substantially all the net assets of the Company’s subsidiaries were restricted. Accordingly, these condensed parent only financial statements have been prepared pursuant to Rule 5-04 of Regulation S-X of the Securities Exchange Act of 1934, as amended.
Note 2 — Notes Receivable
The Company has advanced $171.0 million under promissory notes to its wholly owned subsidiary, which bear a simple interest rate of 9.75% per annum. Interest on notes receivable amounted to approximately $16.7 million for each of the years ended June 30, 2015, June 30, 2014 and June 30, 2013.
Note 3 — Long-Term Debt
On November 18, 2013, the Company sold $400 million face value of 3.0% Senior Convertible Notes due 2018 (the “3.0% Senior Convertible Notes”). The Company incurred underwriting and direct offering costs of $7.6 million which have been capitalized and are being amortized over the life of the 3.0% Senior Convertible Notes. The 3.0% Senior Convertible Notes are convertible into cash, shares of common stock or a combination of cash and shares of common stock, at the Company’s election, based on an initial conversion rate of 24.7523 shares of common stock per $1,000 principal amount of the 3.0% Senior Convertible Notes (equivalent to an initial conversion price of approximately $40.40 per share of common stock). The conversion rate, and accordingly the conversion price, may be adjusted under certain circumstances as described in the indenture governing the 3.0% Senior Convertible Notes.
For accounting purposes, the $400 million aggregate principal amount of 3.0% Senior Convertible Notes for which we received cash was recorded at fair market value by applying the implied straight debt rate of 6.75% to allocate the proceeds between the debt component and the convertible equity component of the 3.0% Senior Convertible Notes. Based on applying the implied straight debt rate, the $400 million aggregate principal amount of the 3.0% Senior Convertible Notes was recorded at $336.6 million and the $63.4 million original issue discount is being amortized as an increase in interest expense over the life of the 3.0% Senior Convertible Notes.
Note 4 — Guarantee
The Company has provided a guarantee related to the payment of asset retirement obligations and other liabilities by M21K, LLC (“M21K”) for the EP Energy, LLOG Exploration and Eugene Island 330 and South Marsh Island 128 property acquisitions. For these guarantees, M21K has agreed to pay us $6.3 million, $3.3 million and $1.7 million, respectively, over a period of three years from the respective acquisition dates. For the years ended June 30, 2015, 2014 and 2013, we have received $3.7 million, $3.1 million and $1.9 million, respectively, related to such guarantees. On August 11, 2015, our wholly owned subsidiary acquired all equity interests in EXXI M21K.
294
ENERGY XXI LTD
NOTES TO CONDENSED FINANCIAL STATEMENTS
Note 4 — Guarantee – (continued)
The Company has guaranteed the obligations under the lease agreement entered into by its wholly owned subsidiary under which such subsidiary will operate the Grand Isle Gathering System (the “GIGS Lease”). The primary term of the GIGS Lease is 11 years, with one renewal option, which will be the lesser of nine years or 75% of the expected remaining useful life of the Grand Isle Gathering System. The operating lease utilizes a minimum rent plus a variable rent structure, which is linked to the oil revenues realized from the Grand Isle Gathering System above a predetermined oil revenue threshold. The aggregate annual minimum monthly payments for the first twelve months of the GIGS Lease total $31.5 million, and such payment amounts average $40.5 million per year over the life of the lease.
Note 5 — Income Taxes
The Company is incorporated in Bermuda and is generally not subject to income tax in Bermuda. The Company operates through its various subsidiaries in the United States; accordingly income taxes have been provided based upon U.S. tax laws and rates as they apply to the Company’s current ownership structure. The Company is subject to 30% U.S. withholding taxes on payments made to it for interest on indebtedness and guarantee provided.
Note 6 — Supplemental Cash Flow Information
The following table presents our supplemental cash flow information(in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Cash paid for interest | $ | 12,000 | $ | 6,767 | $ | — |
The following table presents our non-cash investing and financing activities(in thousands):
Year Ended June 30, | ||||||||||||
2015 | 2014 | 2013 | ||||||||||
Common stock issued for the EPL Acquisition, net | $ | — | $ | 315,394 | $ | — |
(3) Exhibits
The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the Exhibit Index accompanying this Form 10-K and are incorporated herein by reference.
295
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 29th day of September 2015.
ENERGY XXI LTD
By: | /s/ JOHN D. SCHILLER, JR. John D. Schiller, Jr. Chairman of the Board and Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ JOHN D. SCHILLER, JR. John D. Schiller, Jr. | Chairman of the Board and Chief Executive Officer (Principal Executive Officer) | September 29, 2015 | ||
/s/ BRUCE W. BUSMIRE Bruce W. Busmire | Chief Financial Officer and (Principal Financial Officer and Principal Accounting Officer) | September 29, 2015 | ||
/s/ WILLIAM COLVIN William Colvin | Director | September 29, 2015 | ||
/s/ CORNELIUS DUPRÉ II Cornelius Dupré II | Director | September 29, 2015 | ||
/s/ HILL A. FEINBERG Hill A Feinberg | Director | September 29, 2015 | ||
/s/ KEVIN S. FLANNERY Kevin S. Flannery | Director | September 29, 2015 | ||
/s/ SCOTT A. GRIFFITHS Scott A. Griffiths | Director | September 29, 2015 | ||
/s/ JAMES LACHANCE James LaChance | Director | September 29, 2015 | ||
/s/ NORMAN LOUIE Norman Louie | Director | September 29, 2015 |
296
EXHIBIT INDEX
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
2.1 | Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of March 12, 2014 | Included as Annex A to the Registration Statement on Form S-4 filed on April 1, 2014 | 333-194942 | |||
2.2 | Amendment No. 1 to Agreement and Plan of Merger among Energy XXI (Bermuda) Limited, Energy XXI Gulf Coast, Inc., Clyde Merger Sub, Inc. and EPL Oil & Gas, Inc., dated as of April 15, 2014 | 2.2 to Energy XXI (Bermuda) Limited’s Form S-4/A filed on April 15, 2014 | 333-194942 | |||
2.3 | Purchase and Sale Agreement, dated June 22, 2015, by and between Grand Isle Corridor, LP and Energy XXI USA, Inc. | 2.1 to the Company’s Form 8-K filed on June 23, 2015 | 001-33628 | |||
2.4 | Guaranty, dated June 22, 2015, by Energy XXI Ltd in favor of Grand Isle Corridor, LP | 2.2 to the Company’s Form 8-K filed on June 23, 2015 | 001-33628 | |||
2.5 | Guaranty, dated June 22, 2015, by CorEnergy Infrastructure Trust, Inc. in favor of Energy XXI USA, Inc. | 2.3 to the Company’s Form 8-K filed on June 23, 2015 | 001-33628 | |||
3.1 | Altered Memorandum of Association of Energy XXI Ltd | 3.1 to the Company’s Form 8-K filed on November 9, 2011 | 001-33628 | |||
3.2 | Bye-Laws of Energy XXI Ltd | 3.2 to the Company’s Form 8-K filed on November 9, 2011 | 001-33628 | |||
4.1 | Investor Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) Limited, Sunrise Securities Corp. and Collins Steward Limited | 4.1 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007 | 333-145639 | |||
4.2 | Registration Rights Agreement dated October 13, 2005 among Energy XXI Acquisition Corporation (Bermuda) and the investors named therein | 4.2 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007 | 333-145639 | |||
4.3 | Indenture related to the 9.25% Senior Notes due 2017, dated December 17, 2010, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, N.A., as trustee | 4.1 to the Company’s Form 8-K filed on December 22, 2010 | 001-33628 | |||
4.4 | Indenture related to the 7.75% Senior Notes due 2019, dated as of February 25, 2011 among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee | 4.1 to the Company’s Form 8-K filed on February 28, 2011 | 001-33628 |
297
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
4.5 | Indenture related to the 7.50% Senior Notes due 2021, dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Energy XXI (Bermuda) Limited, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee | 4.1 to the Company’s Form 8-K filed on September 26, 2013 | 001-33628 | |||
4.6 | Registration Rights Agreement dated as of September 26, 2013 among Energy XXI Gulf Coast, Inc., Citigroup Global Markets Inc. and RBS Securities Inc., as representatives of the Initial Purchasers, Energy XXI (Bermuda) Limited and the Guarantors named therein | 4.2 to the Company’s Form 8-K filed on September 26, 2013 | 001-33628 | |||
4.7 | Indenture related to the 3.0% Senior Convertible Notes due 2018, dated November 22, 2013, by and between Energy XXI (Bermuda) Limited and Wells Fargo Bank, National Association, as trustee (including the form of 3.0% Senior Convertible Note due 2018) | 4.1 to the Company’s Form 8-K filed on November 22, 2013 | 001-33628 | |||
4.8 | Indenture related to the 6.875% Senior Notes due 2024, dated as of May 27, 2014, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, as trustee | 4.1 to the Company’s Form 8-K filed on May 29, 2014 | 001-33628 | |||
4.9 | Registration Rights Agreement dated as of May 27, 2014 among Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC and Citigroup Global Markets Inc., as representatives of the Initial Purchasers and the Guarantors named therein | 4.2 to the Company’s Form 8-K filed on May 29, 2014 | 001-33628 | |||
4.10 | Indenture related to the 8.25% Senior Notes due 2018, dated as of February 14, 2011, by and among Energy Partners, Ltd., as Issuer, the Guarantors named therein and U.S. Bank National Association, as Trustee | 4.1 to EPL Oil & Gas, Inc. Form 8-K filed on February 15, 2011 | 001-16179 | |||
4.11 | Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated as of March 14, 2011, by and among Anglo-Suisse Offshore Pipeline Partners, LLC, as a Guarantor, Energy Partners, Ltd., as Issuer, the other Guarantors named therein and U.S. Bank National Association, as Trustee | 4.2 to EPL Oil & Gas, Inc. Form S-4 filed on August 14, 2011 | 333-175567 | |||
298
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
4.12 | Second Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee | 4.3 to EPL Oil & Gas, Inc. Form 10-K filed on March 7, 2013 | 001-16179 | |||
4.13 | Indenture related to the 8.25% Senior Notes due 2018, dated October 25, 2012, by and among EPL Oil & Gas, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee | 4.1 to EPL Oil & Gas, Inc. Form 8-K filed on October 30, 2012 | 001-16179 | |||
4.14 | First Supplemental Indenture related to the 8.25% Senior Notes due 2018, dated October 31, 2012, by and among Hilcorp Energy GOM, LLC, as a Guarantor, EPL Oil & Gas, Inc., as Issuer, the other Guarantors named therein, and U.S. Bank National Association, as Trustee | 4.5 to EPL Oil & Gas, Inc. Form 10-K filed on March 7, 2013 | 001-16179 | |||
4.15 | Third Supplemental Indenture related to the 8.25% Senior Notes due 2018, by and among EPL Oil & Gas, Inc., the other Guarantors named therein and U.S. Bank National Association, as Trustee, dated April 18, 2014 | 4.1 to EPL Oil & Gas, Inc. Form 8-K filed on April 21, 2014 | 001-16179 | |||
4.16 | Indenture, related to the 11.000% Senior Secured Second Lien Notes due 2020, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., the Guarantors named therein and U.S. Bank National Association, as Trustee | 10.1 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.1† | Form of Restricted Stock Grant Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC | 10.6 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007 | 333-145639 | |||
10.2† | Form of Restricted Stock Unit Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC | 10.7 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007 | 333-145639 | |||
10.3 | Letter Agreement dated September 2005 between Energy XXI Acquisition Corporation (Bermuda) Limited and The Exploitation Company, L.L.P. | 10.12 to Energy XXI Gulf Coast, Inc. Form S-4 filed on August 22, 2007 | 333-145639 | |||
10.4† | Form of Notice of Grant of Stock Option together with Form of Stock Option Agreement under 2006 Long-Term Incentive Plan of Energy XXI Services, LLC | 10.25 to the Company’s Form 10-K filed on September 11, 2008 | 001-33628 | |||
10.5† | Energy XXI Services, LLC Directors’ Deferred Compensation Plan | 10.1 to the Company’s Form 8-K filed on September 10, 2008 | 001-33628 |
299
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
10.6† | Employment Agreement of John D. Schiller, Jr., effective September 10, 2008 | 10.1 to the Company’s Form 8-K filed on September 11, 2008 | 001-33628 | |||
10.7† | Form of Indemnification Agreement between Energy XXI (Bermuda) Limited and Indemnitees | 10.1 to the Company’s Form 8-K filed on November 5, 2008 | 001-33628 | |||
10.8† | Form of Indemnification Agreement Between Company Subsidiaries and Indemnitees | 10.2 to the Company’s Form 8-K filed on November 5, 2008 | 001-33628 | |||
10.9† | Energy XXI Services, LLC Employee Stock Purchase Plan | 10.1 to the Company’s Form 8-K filed on November 5, 2008 | 001-33628 | |||
10.10† | Energy XXI Services, LLC 2008 Fair Market Value Stock Purchase Plan | 4.2 to Form S-8 filed on June 10, 2009 | 333-159868 | |||
10.11† | Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Restricted Stock Unit Awards Agreement | 10.20 to the Company’s Form 10-K filed on August 9, 2012 | 001-33628 | |||
10.12† | Energy XXI Services, LLC, 2006 Long-Term Incentive Plan Performance Unit Awards Agreement | 10.14 to the Company’s Form 10-K filed on August 25, 2014 | 001-33628 | |||
10.13† | Energy XXI Services, LLC, Employee Severance Plan (Amended and Restated August 1, 2014) | 10.15 to the Company’s Form 10-K filed on August 25, 2014 | 001-33628 | |||
10.14† | Amended and Restated 2006 Long-Term Incentive Plan of Energy XXI Services, LLC | 10.1 to Form S-8 filed on December 15, 2009 | 333-163736 | |||
10.15† | Release and Separation Agreement, by and between David West Griffin and Energy XXI Ltd, dated December 4, 2014 | 10.1 to the Company’s Form 8-K filed on December 5, 2014 | 001-33628 | |||
10.16† | Release and Separation Agreement, by and between Benjamin Marchive and Energy XXI (Bermuda) Limited, dated August 20, 2014 | 10.2 to the Company’s Form 10-Q filed on February 9, 2015 | 001-33628 | |||
10.17 | Second Amended and Restated First Lien Credit Agreement, dated as of May 5, 2011, among Energy XXI Gulf Coast, Inc., the various financial institutions and other parties from time to time parties thereto, as lenders, The Royal Bank of Scotland plc, as administrative Agent, and the other persons parties thereto in the capacities specified therein | 10.1 to the Company’s Form 8-K filed on May 6, 2011 | 001-33628 | |||
10.18 | First Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 4, 2011 | 10.1 to the Company’s Form 8-K filed on October 4, 2011 | 001-33628 | |||
10.19 | Second Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 24, 2012 | 10.1 to the Company’s Form 8-K filed on May 25, 2012 | 001-33628 |
300
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
10.20 | Third Amendment to Second Amended and Restated First Lien Credit Agreement dated as of October 19, 2012 | 10.1 to the Company’s Form 8-K filed on October 15, 2012 | 001-33628 | |||
10.21 | Fourth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 9, 2013 | 10.1 to the Company’s Form 8-K filed on April 10, 2013 | 001-33628 | |||
10.22 | Fifth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 1, 2013 | 10.1 to the Company’s Form 8-K filed on May 6, 2013 | 001-33628 | |||
10.23 | Sixth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of September 27, 2013 | 10.1 to the Company’s Form 8-K filed on September 27, 2013 | 001-33628 | |||
10.24 | Seventh Amendment to Second Amended and Restated First Lien Credit Agreement dated as of April 7, 2014 | 10.1 to the Company’s Form 8-K filed on April 7, 2014 | 001-33628 | |||
10.25 | Eighth Amendment to Second Amended and Restated First Lien Credit Agreement dated as of May 23, 2014 | 10.25 to the Company’s form 10-K filed on August 25, 2014 | 001-33628 | |||
10.26 | Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of August 22, 2014 | 10.26 to the Company’s form 10-K filed on August 25, 2014 | 001-33628 | |||
10.27 | Ninth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of September 5, 2015 | 10.1 to the Company’s Form 8-K filed on September 9, 2014 | 001-33628 | |||
10.28 | Tenth Amendment to Second Amended and Restated First Lien Credit Agreement, dated as of March 3, 2015 | 10.2 to the Company’s Form 10-Q filed on May 8, 2015 | 001-33628 | |||
10.29 | Eleventh Amendment and Waiver to Second Amended and Restated First Lien Credit Agreement, dated as of July 31, 2015 | Filed herewith | ||||
10.30 | Energy XXI Services, LLC Restoration Plan Amended and Restated effective January 1, 2013 | 10.1 to the Company’s Form 10-Q filed on January 31, 2013 | 001-33628 | |||
10.31 | Form of Energy XXI Voting Agreement, dated as of March 12, 2014 | 10.1 to the Company’s Form 8-K filed on March 13, 2013 | 001-33628 | |||
10.34 | Form of EPL Oil & Gas Voting Agreement, dated as of March 12, 2014 | 10.2 to the Company’s Form 8-K filed on March 13, 2014 | 001-33628 | |||
10.33 | Interim Chief Strategic Officer Agreement, dated as of February 23, 2015, between Energy XXI Services, LLC and James LaChance. | 10.1 to the Company’s Form 8-K filed on February 25, 2015 | 001-33628 |
301
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
10.34 | Purchase Agreement, dated March 5, 2015, by and between Energy XXI Gulf Coast, Inc., Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Wells Fargo Securities, LLC and Imperial Capital, LLC, as representatives of the Initial Purchasers, and the Guarantors named therein | 10.1 to the Company’s Form 8-K filed on March 9, 2015 | 001-33628 | |||
10.35 | Intercreditor Agreement, dated as of March 12, 2015, by and between U.S. Bank National Association, as Collateral Trustee, and the Royal Bank of Scotland plc, as Priority Lien Agent | 10.1 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.36 | Collateral Trust Agreement, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., the Guarantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Parity Lien Debt Representatives from time to time party thereto and U.S. Bank National Association, as Collateral Trustee | 10.2 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.37 | Second Lien Pledge and Security Agreement and Irrevocable Proxy, dated as of March 12, 2015, by and among Energy XXI Gulf Coast, Inc., each Subsidiary Guarantor (as defined in the Indenture) party thereto and U.S. Bank National Association, as Collateral Trustee | 10.3 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.38 | Second Lien Pledge Agreement and Irrevocable Proxy, dated as of March 12, 2015, by and between Energy XXI USA, Inc. and U.S. Bank National Association, as Collateral Trustee | 10.4 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.39 | Second Lien Security Agreement relating to the Grand Isle Gathering System Assets, dated as of March 12, 2015, by and between Energy XXI USA, Inc. and U.S. Bank National Association, as Collateral Trustee | 10.5 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.40 | Secured Second Lien Promissory Note, dated as of March 12, 2015, issued by EPL Oil & Gas, Inc., as the Maker, in favor of Energy XXI Gulf Coast, Inc., as the Payee | 10.6 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.41 | Guaranty, dated as of March 12, 2015, issued by the subsidiaries of EPL Oil & Gas, Inc., in favor of Energy XXI Gulf Coast, Inc., as Lender | 10.7 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 |
302
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
10.42 | Second Lien Pledge and Security Agreement and Irrevocable Proxy, dated as of March 12, 2015, by EPL Oil & Gas, Inc. and each Subsidiary Guarantor Party thereto, in favor of Energy XXI Gulf Coast, Inc., as Lender | 10.8 to the Company’s Form 8-K filed on March 17, 2015 | 001-33628 | |||
10.43 | Intercompany Intercreditor Agreement, dated as of March 12, 2015, between the Royal Bank of Scotland plc, as Priority Lien Agent and Energy XXI Gulf Coast, Inc. | 10.12 to the Company’s Form 10-Q filed on May 8, 2015 | 001-33628 | |||
10.44 | Transportation Agreement, dated as of March 11, 2015, between Energy XXI Gulf Coast, Inc. and Energy XXI USA, Inc. | 10.13 to the Company’s Form 10-Q filed on May 8, 2015 | 001-33628 | |||
10.45 | Assignment and Bill of Sale, dated March 11, 2015, by and among Energy XXI GOM, LLC, Energy XXI Pipeline, LLC, Energy XXI Pipeline II, LLC, and Energy XXI USA, Inc. | 10.14 to the Company’s Form 10-Q filed on May 8, 2015 | 001-33628 | |||
10.46 | Lease, dated June 30, 2015, by and between Grand Isle Corridor, LP and Energy XXI GIGS Services, LLC | 10.1 to the Company’s Form 8-K filed on July 1, 2015 | 001-33628 | |||
12.1 | Ratio of Earnings (Loss) to Combined Fixed Charges and Preference Dividends – Energy XXI Ltd | Filed herewith | ||||
21.1 | Subsidiary List | Filed herewith | ||||
23.1 | Consent of BDO USA, LLP | Filed herewith | ||||
23.2 | Consent of UHY, LLP | Filed herewith | ||||
23.3 | Consent of Netherland, Sewell & Associates, Inc. | Filed herewith | ||||
31.1 | Certification of Chief Executive Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith | ||||
31.2 | Certification of Chief Financial Officer Pursuant to Rule 13a — 14 of the Securities and Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | Filed herewith | ||||
32.1 | Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | Filed herewith | ||||
99.1 | Report of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers and Geologists | Filed herewith |
303
Exhibit Number | Exhibit Description | Originally Filed as Exhibit | File Number | |||
101.INS | XBRL Instance Document | Filed herewith | ||||
101.SCH | XBRL Taxonomy Extension Schema Document | Filed herewith | ||||
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | Filed herewith | ||||
101.DEF | XBRL Taxonomy Extension Label Linkbase Document | Filed herewith | ||||
101.LAB | XBRL Taxonomy Extension Definition Linkbase Document | Filed herewith | ||||
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | Filed herewith |
304