424B3 1 d608312d424b3.htm 424B3 424B3
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Filed Pursuant to Rule 424(b)(3)
Registration No. 333-227362

PROSPECTUS

TALOS PRODUCTION LLC

TALOS PRODUCTION FINANCE INC.

Exchange Offer for

$390,867,820 11.00% Second-Priority Senior Secured Notes due 2022

and Related Guarantees

The Notes and the Guarantees

 

   

Talos Production LLC and Talos Production Finance Inc. are offering (the “Exchange Offer”) to issue $390,867,820 aggregate principal amount of their new 11.00% Second-Priority Senior Secured Notes due 2022 and related guarantees (collectively, the “Exchange Notes”), which issuance is registered under the Securities Act of 1933, in exchange for their existing $390,867,820 aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 (CUSIP Nos. 87484JAD2, 87484JAE0 and U83041AC4) and related guarantees (collectively, the “Initial Notes”). Unless the context otherwise requires, we refer to the Initial Notes and the Exchange Notes, collectively, as the “Notes.”

 

   

The Exchange Notes will mature on April 3, 2022. We will pay interest on the Exchange Notes semi-annually on April 15 and October 15 of each year at a rate of 11.00% per annum, to holders of record at the close of business on the April 1 or October 1 immediately preceding the interest payment date.

 

   

Our obligations under the Exchange Notes will be fully and unconditionally guaranteed, jointly and severally, by Talos Energy Inc., our parent company, and by our present and future direct or indirect wholly-owned material domestic restricted subsidiaries that guarantee our senior reserve-based revolving credit facility (the “Bank Credit Facility”).

 

   

The Exchange Notes and the related guarantees will be senior second-priority secured obligations and will (i) rank equal in right of payment with all of our existing and future senior indebtedness, (ii) rank senior in right of payment to all of our existing and future indebtedness and other obligations that are, by their terms, expressly subordinated in right of payment to the Notes, (iii) be effectively senior to all of our existing and future unsecured indebtedness, to the extent of the value of the collateral securing the Notes, (iv) rank equal with all of our existing and future indebtedness that is secured by the collateral on a second-priority basis, to the extent of the value of the collateral, (v) be effectively junior to all of our existing and future indebtedness that is secured on a senior-priority basis, including indebtedness under the Bank Credit Facility, to the extent of the value of the collateral and (vi) be structurally subordinated to all existing and future indebtedness and other liabilities of each of our subsidiaries that is not a guarantor of the Notes.

Terms of the Exchange Offer

 

   

The Exchange Offer will expire at 5:00 p.m., New York City time, on October 26, 2018, unless we extend it.

 

   

If all the conditions to this Exchange Offer are satisfied, we will exchange all of our Initial Notes that are validly tendered and not withdrawn for the Exchange Notes.

 

   

You may withdraw your tender of Initial Notes at any time before the expiration of this Exchange Offer.

 

   

The Exchange Notes that we will issue you in exchange for your Initial Notes will be substantially identical to your Initial Notes except that, unlike your Initial Notes, the Exchange Notes will have no transfer restrictions or registration rights.


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The Exchange Notes that we will issue you in exchange for your Initial Notes are new securities with no established market for trading.

Before participating in this Exchange Offer, please refer to the section in this prospectus entitled “Risk Factors” commencing on page 12.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

We have not applied, and do not intend to apply, for listing or quotation of the Notes on any national securities exchange or automated quotation system.

Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act of 1933, as amended. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Initial Notes where such Initial Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration date of the Exchange Offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

 

 

The date of this prospectus is September 27, 2018.


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TABLE OF CONTENTS

 

     Page  

Prospectus Summary

     1  

Summary of the Exchange Offer

     3  

Summary of Terms of the Exchange Notes

     8  

Risk Factors

     12  

Use of Proceeds

     55  

Capitalization

     56  

Ratio of Earnings to Fixed Charges

     57  

Selected Historical Financial Data

     58  

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

     59  

Business

     89  

Management

     115  

Compensation Discussion and Analysis

     124  

Security Ownership of Certain Beneficial Owners and Management

     138  

Certain Relationships and Related Party Transactions

     141  

The Exchange Offer

     145  

Description of Other Indebtedness

     154  

Description of the Notes

     155  

Certain U.S. Federal Income Tax Considerations

     234  

Plan of Distribution

     235  

Legal Matters

     236  

Experts

     236  

Where You Can Find More Information

     239  

Index to Financial Statements

     F-1  

Financial Statements

     F-2  

We have not authorized anyone to give you any information or to make any representations about us or the transactions we discuss in this prospectus other than those contained in this prospectus. If you are given any information or representations about these matters that is not discussed in this prospectus, you must not rely on that information. This prospectus is not an offer to sell or a solicitation of an offer to buy securities anywhere or to anyone where or to whom we are not permitted to offer or sell securities under applicable law. The delivery of this prospectus does not, under any circumstances, mean that there has not been a change in our affairs since the date of this prospectus. Subject to our obligation to amend or supplement this prospectus as required by law and the rules and regulations of the SEC, the information contained in this prospectus is correct only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of these securities.

Until December 26, 2018 (90 days after the date of this prospectus), all dealers effecting transactions in the Exchange Notes, whether or not participating in the Exchange Offer, may be required to deliver a prospectus. This is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Each prospective purchaser of the Exchange Notes must comply with all applicable laws and regulations in force in any jurisdiction in which it purchases, offers or sells the Notes or possesses or distributes this prospectus and must obtain any consent, approval or permission required by it for the purchase, offer or sale by it of the additional Exchange Notes under the laws and regulations in force in any jurisdiction to which it is subject or in which it makes such purchases, offers or sales, and we shall not have any responsibility therefor.

 

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BASIS OF PRESENTATION

On May 10, 2018 (the “Closing Date”), Talos Energy Inc., a Delaware corporation (formerly named Sailfish Energy Holdings Corporation) consummated the transactions contemplated by the Transaction Agreement, dated as of November 21, 2017, among Stone Energy Corporation, Talos Energy Inc., Sailfish Merger Sub Corporation, Talos Energy LLC and Talos Production LLC, pursuant to which each of Stone Energy Corporation and Talos Energy LLC became wholly owned subsidiaries of Talos Energy Inc.

In this prospectus, unless otherwise indicated or the context otherwise requires, references to the “Company,” “we,” “us,” “our,” “Talos,” and “Talos Energy” refer to, from and after the Closing Date, Talos Energy Inc. and its consolidated subsidiaries, including Talos Production LLC (“Holdings”) and Talos Production Finance Inc. (the “Co-Issuer” and, together with Holdings, the “Issuers”), and prior to the Closing Date, Talos Energy LLC and its consolidated subsidiaries, including the Issuers.

This prospectus contains financial statements for the years ended December 31, 2017, 2016 and 2015 for Talos Energy Inc. (formerly known as Talos Energy LLC) and for the six months ended June 30, 2018 and 2017 for Talos Energy Inc.

This prospectus also contains the financial statements of Stone Energy Corporation for the period from March 1, 2017 through December 31, 2017, the period from January 1, 2017 through February 28, 2017 and the years ended December 31, 2016 and 2015, and for the three months ended March 31, 2018 and the period from March 1, 2017 through March 31, 2017 and the period from January 1, 2017 through February 28, 2017.

USE OF SUPPLEMENTAL NON-GAAP FINANCIAL INFORMATION

“Adjusted EBITDA” is not a measure of net income (loss) as determined by accounting principles generally accepted in the United States of America (“GAAP”). We use this measure as a supplemental measure because we believe it provides meaningful information to our investors. Adjusted EBITDA is presented in this prospectus as a supplemental measure that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income (loss) plus interest expense, depreciation, depletion and amortization, accretion expense, loss on debt extinguishment, transaction related costs, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), non-cash write-down of oil and natural gas properties, non-cash write-down of other well equipment inventory and non-cash equity based compensation expense. We believe the presentation of Adjusted EBITDA is important to provide management and investors with (i) additional information to evaluate items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

For more information on the use of non-GAAP financial information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Supplemental Non-GAAP Measure.”

PV-10 is a non-GAAP financial measure and was prepared using SEC pricing discounted at 10% per annum, without giving effect to income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Moreover, GAAP does not provide a measure of

 

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estimated future net cash flows for reserves other than proved reserves or for proved, probable or possible reserves calculated using prices other than SEC prices. PV-10 estimates for price sensitivities are not adjusted for the likelihood that the relevant pricing scenario will occur. Investors should be cautioned that neither PV-10 nor standardized measure represent an estimate of the fair market value of our proved reserves.

MARKET AND INDUSTRY DATA

We include statements regarding factors that have impacted our and our customers’ industries, such as our customers’ access to capital. Such statements regarding our and our customers’ industries and market share or position are statements of belief and are based on market share and industry data and forecasts that we have obtained from industry publications and surveys, as well as internal company sources. Industry publications, surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of such information. We have not independently verified any of the data from third-party sources, nor have we ascertained the underlying economic assumptions relied upon therein. In addition, while we believe that the market share, market position and other industry information included herein is generally reliable, such information is inherently imprecise. While we are not aware of any misstatements regarding our industry data presented herein, our estimates involve risks and uncertainties and are subject to change based on various factors, including those discussed under the caption “Risk Factors” in this prospectus.

TRADEMARKS AND TRADE NAMES

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information in this prospectus includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

 

   

business strategy;

 

   

reserves;

 

   

exploration and development drilling prospects, inventories, projects and programs;

 

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our ability to replace the reserves that we produce through drilling and property acquisitions;

 

   

financial strategy, liquidity and capital required for our development program;

 

   

realized oil and natural gas prices;

 

   

timing and amount of future production of oil, natural gas and NGLs;

 

   

our hedging strategy and results;

 

   

future drilling plans;

 

   

competition and government regulations;

 

   

our ability to obtain permits and governmental approvals;

 

   

pending legal or environmental matters;

 

   

our marketing of oil, natural gas and NGLs;

 

   

leasehold or business acquisitions;

 

   

costs of developing properties;

 

   

general economic conditions;

 

   

credit markets;

 

   

uncertainty regarding our future operating results; and

 

   

plans, objectives, expectations and intentions contained in this report that are not historical.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, well control risk, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, potential adverse reactions or changes to business or employee relations resulting from the business combination between Talos Energy LLC and Stone Energy Corporation, competitive responses to such business combination, the possibility that the anticipated benefits of such business combination are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of the two companies, litigation relating to the business combination, and the other risks discussed in “Risk Factors” herein.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before exchanging your Initial Notes for the Exchange Notes. You should carefully read the entire prospectus, including the information presented under the section entitled “Risk Factors,” and the historical financial data and related notes, before making any decision. This summary contains forward-looking statements that involve risks and uncertainties. Our actual results may differ significantly from the results discussed in the forward-looking statements as a result of certain factors, including those set forth in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Our Company

We are a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico. For more information about our company, see “Business” beginning on page 89 of this prospectus.

Our principal executive offices are located at 333 Clay Street, Suite 3300, Houston, Texas 77002, and our telephone number at that address is (713) 328-3000.

The Transactions

On May 10, 2018 (the “Closing Date”), Talos Energy Inc. (f/k/a Sailfish Energy Holdings Corporation) consummated the transactions contemplated by that certain Transaction Agreement, dated as of November 21, 2017 (the “Transaction Agreement”), among Stone Energy Corporation (“Stone” or “Stone Energy”), Talos Energy Inc., Sailfish Merger Sub Corporation (“Merger Sub”), Talos Energy LLC and Talos Production LLC, pursuant to which each of Stone, Talos Production LLC and Talos Energy LLC became wholly-owned subsidiaries of Talos Energy Inc. (the “Stone Combination”). Prior to the Closing Date, Sailfish Energy Holdings Corporation did not conduct any material activities other than those incident to its formation and the matters contemplated by the Transaction Agreement. Substantially concurrent with the consummation of the transactions, the name of the Company was changed from Sailfish Energy Holdings Corporation to Talos Energy Inc.

Pursuant to the Transaction Agreement, a series of transactions occurred on the Closing Date (the “Closing”), including: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and a direct wholly-owned subsidiary of the Company (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of the Company’s common stock, par value $0.01 (the “Common Stock”) and (ii) in a series of contributions, entities related to Apollo Management VII, L.P. (“Apollo VII”), Apollo Commodities Management, L.P., with respect to Series I (“Apollo Commodities Management” and, together with Apollo VII, “Apollo Funds”) and Riverstone Energy Partners V, L.P. (“Riverstone Funds”) contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to the Company in exchange for an aggregate of 31,244,085 shares of Common Stock (the “Sponsor Equity Exchange”).



 

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Concurrently with the consummation of the Transaction Agreement, the Company consummated the transactions contemplated by that certain Exchange Agreement, dated as of November 21, 2017 (the “Exchange Agreement”), among the Company, Stone, the Issuers, the various lenders and noteholders of the Issuers listed therein, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) (such controlled noteholders, the “Franklin Noteholders”), and certain clients of MacKay Shields LLC (“MacKay Shields”) (such noteholders, the “MacKay Noteholders”), pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 issued by the Issuers to the Company in exchange for an aggregate of 2,874,049 shares of Common Stock (the “Sponsor Notes Exchange” and together with the Sponsor Equity Exchange, the “Sponsor Exchanges” and the Common Stock issued pursuant thereto, the “Private Placement”); (ii) the holders (the “Bridge Loan Lenders”) of second lien bridge loans (the “Bridge Loans”) issued by the Issuers exchanged such Bridge Loans for $172.0 million aggregate principal amount of Initial Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“Stone Notes”) for $137.4 million aggregate principal amount of Initial Notes.

As a result of the closing of the transactions contemplated by the Transaction Agreement and the Exchange Agreement (the “Transactions”), AP Talos Energy LLC, AP Talos Energy Debtco LLC (together, the “Apollo Feeders”), AP Overseas Talos Holdings Partnership, LLC, AIF VII (AIV), L.P., ANRP DE Holdings, L.P., a Delaware limited partnership (collectively, the “Apollo Blockers” and, together with the Apollo Feeders, the “Apollo Stockholders”), Riverstone Talos Energy Equityco LLC, Riverstone Talos Energy Debtco LLC (together, the “Riverstone Feeders”) and Riverstone V FT Corp Holdings, L.P. (the “Riverstone Blocker” and, together with the Riverstone Feeders, the “Riverstone Stockholders” and, collectively with the Apollo Stockholders, the “Sponsor Stockholders”) collectively held approximately 63% of the Company’s outstanding Common Stock, and the former stockholders of Stone, including certain funds controlled by Franklin and certain clients of MacKay Shields, held approximately 37% of the Company’s outstanding Common Stock as of the Closing Date.

Recent Developments

On August 31, 2018, we completed the acquisition of Whistler Energy II, LLC (“Whistler”). We paid the sellers $52 million in cash. We also secured the release of approximately $77 million of cash collateral that had secured Whistler’s surety bonds, of which we received $31 million and the seller received the remaining $46 million. We will not have to replace this cash collateral. In addition, we also acquired $7 million in available cash from Whistler at closing. As a result of these items the net cash outflow for this acquisition was $14 million. The acquired assets include a 100% working interest in three blocks in the Central Gulf of Mexico – Green Canyon 18, Green Canyon 60 and Ewing Bank 988, which comprises 16,494 acres, and a fixed production platform located on Green Canyon Block 18 in approximately 750 feet of water. All leases are held-by-production. Year to date gross production from Whistler’s assets is approximately 1,900 barrels of oil equivalent per day (“Boepd”), or net production after royalties of approximately 1,500 Boepd, of which 82% is oil.



 

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SUMMARY OF THE EXCHANGE OFFER

 

Exchange Offer

Talos Production LLC and Talos Production Finance Inc. are offering (the “Exchange Offer”) to issue $390,867,820 aggregate principal amount of their 11.00% Second-Priority Senior Secured Notes due 2022 (collectively, the “Exchange Notes”), which issuance is registered under the Securities Act of 1933, in exchange for their existing $390,867,820 aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 (CUSIP Nos. 87484JAD2, 87484JAE0 and U83041AC4) and related guarantees (collectively, the “Initial Notes”). Unless the context otherwise requires, we refer to the Initial Notes and the Exchange Notes, collectively, as the “Notes.”

 

  The Initial Notes were issued and the Exchange Notes will be issued under the same indenture.

 

  In order to exchange your Initial Notes, you must properly tender your Initial Notes and we must accept the Initial Notes you tender. We will exchange all outstanding Initial Notes that are validly tendered and not validly withdrawn prior to the expiration or termination of the Exchange Offer. Initial Notes may be exchanged only for a minimum principal denomination of $2,000 and in integral multiples of $1.00 in excess thereof.

 

Expiration Date

This Exchange Offer will expire at 5:00 p.m., New York City time, on October 26, 2018, unless we decide to extend it in our sole discretion.

 

Exchange Notes

The Exchange Notes will be materially identical in all respects to the Initial Notes except that:

 

   

the issuance of the Exchange Notes has been registered under the Securities Act, and the Exchange Notes will be freely tradable by persons who are not affiliates of ours or subject to restrictions due to being broker-dealers;

 

   

the Exchange Notes will not be entitled to the registration rights applicable to the Initial Notes under the registration rights agreement dated May 10, 2018 (the “Registration Rights Agreement”); and

 

   

our obligation to pay additional interest on the Initial Notes due to the failure to consummate the Exchange Offer by a certain date will not apply to the Exchange Notes as the Exchange Notes will have been registered.

 

Conditions to the Exchange Offer

We will complete this Exchange Offer only if:

 

   

there is no change in the laws and regulations which would impair our ability to proceed with this Exchange Offer;

 

   

there is no change in the current interpretation of the staff of the SEC which permits resales of the Exchange Notes;



 

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there is no stop order issued, or proceeding initiated for that purpose, including our receipt of any notice of objection of the SEC to the use of a shelf registration statement or any post-effective amendment thereto pursuant to Rule 401(g)(2) under the Securities Act, by the SEC or any state securities authority which would suspend the effectiveness of the registration statement which includes this prospectus or the qualification of the indenture for the Exchange Notes under the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”);

 

   

there is no litigation restricting our ability to proceed with this Exchange Offer; and

 

   

we obtain all the governmental approvals we deem necessary to complete this Exchange Offer.

 

  Please refer to the section in this prospectus entitled “The Exchange Offer—Conditions to the Exchange Offer.”

 

Procedures for Tendering Initial Notes

To participate in this Exchange Offer, you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your Initial Notes to be exchanged and all other documents required by the letter of transmittal, to Wilmington Trust, National Association, as exchange agent, at its address indicated under “The Exchange Offer—Exchange Agent.” In the alternative, you can tender your Initial Notes by book-entry delivery following the procedures described in this prospectus. For more information on tendering your Initial Notes, please refer to the section in this prospectus entitled “The Exchange Offer—Procedures for Tendering Initial Notes.”

 

Special Procedures for Beneficial Owners

If you are a beneficial owner of Initial Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your Initial Notes in the Exchange Offer, you should contact the registered holder promptly and instruct that person to tender on your behalf.

 

Guaranteed Delivery Procedures

If you wish to tender your Initial Notes and you cannot get the required documents to the exchange agent on time, you may tender your Initial Notes by using the guaranteed delivery procedures described under the section of this prospectus entitled “The Exchange Offer—Procedures for Tendering Initial Notes—Guaranteed Delivery Procedure.”

 

Withdrawal Rights

You may withdraw the tender of your Initial Notes at any time before 5:00 p.m., New York City time, on the expiration date of the Exchange Offer. To withdraw, you must send a written or facsimile transmission notice of withdrawal to the exchange agent at its address indicated under “The Exchange Offer—Exchange Agent” before



 

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5:00 p.m., New York City time, on the expiration date of the Exchange Offer.

 

Acceptance of Initial Notes and Delivery of Exchange Notes

If all the conditions to the completion of this Exchange Offer are satisfied, we will accept any and all Initial Notes that are properly tendered in this Exchange Offer before 5:00 p.m., New York City time, on the expiration date. We will return any Initial Notes that we do not accept for exchange to you without expense promptly after the expiration date. We will deliver the Exchange Notes to you promptly after the expiration date and acceptance of your Initial Notes for exchange. Please refer to the section in this prospectus entitled “The Exchange Offer—Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes.”

 

Federal Income Tax Considerations Relating to the Exchange Offer

We believe that the exchange of the Initial Notes for the Exchange Notes will not be a taxable event to a holder for U.S. federal income tax purposes. Please refer to the section of this prospectus entitled “Certain U.S. Federal Income Tax Considerations.”

 

Exchange Agent

Wilmington Trust, National Association is serving as exchange agent in the Exchange Offer.

 

Fees and Expenses

We will pay all expenses related to this Exchange Offer. Please refer to the section of this prospectus entitled “The Exchange Offer—Fees and Expenses.”

 

Use of Proceeds

We will not receive any proceeds from the issuance of the Exchange Notes. We are making this Exchange Offer solely to satisfy certain of our obligations under the Registration Rights Agreement.

 

Consequences to Holders Who Do Not Participate in the Exchange Offer

If you do not participate in this Exchange Offer:

 

   

except as set forth in the next paragraph, you will not necessarily be able to require us to register your Initial Notes under the Securities Act;

 

   

you will not be able to resell, offer to resell or otherwise transfer your Initial Notes unless they are registered under the Securities Act or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act; and

 

   

the trading market for your Initial Notes will become more limited to the extent other holders of Initial Notes participate in the Exchange Offer.



 

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  You will not be able to require us to register your Initial Notes under the Securities Act unless:

 

   

we determine that the Exchange Offer is not available or cannot be consummated as soon as practicable after the expiration date because it would violate any applicable law or applicable interpretations of the staff of the SEC;

 

   

you notify us within 25 business days of the consummation of the Exchange Offer that you are not eligible to participate in the Exchange Offer due to applicable law or SEC policy or you may not resell the Exchange Notes to the public without delivering a prospectus;

 

  In the latter case, the Registration Rights Agreement requires us to file after completion of the Exchange Offer a shelf registration statement for a continuous offering in accordance with Rule 415 under the Securities Act for the benefit of the holders of the Initial Notes described in this paragraph. We do not currently anticipate that we will register under the Securities Act any Initial Notes that remain outstanding after completion of the Exchange Offer.

 

  Please refer to the section of this prospectus entitled “Risk Factors—Risks Related to the Exchange Offer.”

 

Resales

It may be possible for you to resell the Notes issued in the Exchange Offer without registering the resale of your Notes under the Securities Act and without compliance with the prospectus delivery provisions of the Securities Act, subject to the conditions described under “—Obligations of Broker-Dealers” below.

 

  To tender your Initial Notes in this Exchange Offer and resell the Exchange Notes without compliance with the registration and prospectus delivery requirements of the Securities Act, you must make the following representations:

 

   

you are authorized to tender the Initial Notes and to acquire Exchange Notes, and that we will acquire good and marketable title thereto, free and clear of all liens, restrictions, charges and encumbrances and not subject to any adverse claims when the same are accepted by us;

 

   

the Exchange Notes acquired by you are being acquired in the ordinary course of business;

 

   

you have no arrangement or understanding with any person to participate in a distribution of the Exchange Notes (within the meaning of the Securities Act) and are not participating in, and do not intend to participate in, the distribution of such Exchange Notes;

 

   

you are not an “affiliate” (as defined in Rule 405 under the Securities Act) of ours, or if you are an “affiliate,” you will comply



 

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with the registration and prospectus delivery requirements of the Securities Act to the extent applicable;

 

   

if you are not a broker-dealer, you are not engaging in, and do not intend to engage in, a distribution of Exchange Notes; and

 

   

if you are a broker-dealer, and Initial Notes to be exchanged were acquired by you as a result of market-making or other trading activities, you will deliver a prospectus in connection with any resale, offer to resell or other transfer of such Exchange Notes.

 

  Please refer to the sections of this prospectus entitled “The Exchange Offer—Procedure for Tendering Initial Notes—Proper Execution and Delivery of Letters of Transmittal,” “Risk Factors—Risks Related to the Exchange Offer—Some persons who participate in the Exchange Offer must deliver a prospectus in connection with resales of the Exchange Notes” and “Plan of Distribution.”

 

Obligations of Broker-Dealers

If you are a broker-dealer (1) that receives Exchange Notes, you must acknowledge that you will deliver a prospectus meeting the requirements of the Securities Act in connection with any resales of the Exchange Notes, (2) who acquired the Initial Notes as a result of market-making or other trading activities, you may use the Exchange Offer prospectus as supplemented or amended, in connection with resales of the Exchange Notes, or (3) who acquired the Initial Notes directly from us in the initial offering and not as a result of market-making and trading activities, you must, in the absence of an exemption, comply with the registration and prospectus delivery requirements of the Securities Act in connection with resales of the Exchange Notes.


 

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SUMMARY OF TERMS OF THE EXCHANGE NOTES

In this subsection, “we,” “us” and “our” refer only to Talos Production LLC and Talos Production Finance Inc., as the issuers of the Notes, exclusive of Talos Energy Inc. and our subsidiaries. The terms of the Exchange Notes and those of the outstanding Initial Notes are substantially identical, except that the transfer restrictions and registration rights relating to the Initial Notes do not apply to the Exchange Notes. When we use the term “Notes” in this prospectus, the term includes the Initial Notes and the Exchange Notes. For a more detailed description of the Exchange Notes, see “Description of the Notes.”

 

Issuers

Talos Production LLC and Talos Production Finance Inc.

 

Exchange Notes

Up to $390,867,820 aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022. The form and terms of the Exchange Notes are materially the same as the form and terms of the Initial Notes except that the issuance of the Exchange Notes is registered under the Securities Act, the Exchange Notes will not bear legends restricting their transfer and the Exchange Notes will not be entitled under the Registration Rights Agreement to registration rights or the payment of additional interest under that agreement in the event of a failure to register the Notes. The Exchange Notes will evidence the same debt as the Initial Notes, and both the Initial Notes and the Exchange Notes will be governed by the same indenture.

 

Maturity Date

The Exchange Notes will mature on April 3, 2022.

 

Interest

Interest on the Exchange Notes will accrue at a rate of 11.00% per annum, payable in cash on April 15 and October 15 of each year. Interest will accrue from May 10, 2018.

 

Guarantees

Our obligations under the Exchange Notes will be fully and unconditionally guaranteed, jointly and severally, on a second-priority senior secured basis by Talos Energy Inc., the parent company of Talos Production LLC, and by our present and future direct or indirect wholly-owned material domestic restricted subsidiaries that guarantee the Bank Credit Facility. See “Description of the Notes—Subsidiary Guarantees.”

 

Priority

The Exchange Notes will be our senior secured obligations and will:

 

   

rank equal in right of payment with all of our existing and future senior indebtedness, before giving effect to collateral arrangements;

 

   

rank senior in right of payment to all of our existing and future indebtedness and other obligations that are, by their terms, expressly subordinated in right of payment to the Notes;

 

   

be effectively senior to all of our existing and future unsecured indebtedness, to the extent of the value of the collateral securing the Notes;



 

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rank equal with all of our existing and future indebtedness that is secured by the collateral on a second-priority basis, to the extent of the value of the collateral securing such indebtedness;

 

   

be effectively junior to all of our existing and future indebtedness that is secured on a senior-priority basis, including indebtedness under the Bank Credit Facility, to the extent of the value of the collateral securing such indebtedness; and

 

   

be structurally subordinated to all existing and future indebtedness and other liabilities of each of our subsidiaries that is not a guarantor of the Notes.

 

Security

The Exchange Notes and related guarantees will be secured by second-priority security interests in, subject to permitted liens and certain exceptions described in this prospectus, substantially all of the existing and future assets of the Issuers and the subsidiary guarantors (the “Collateral”), which assets will also secure the Bank Credit Facility on a first-priority basis.

 

  For more information regarding the Collateral, see “Description of the Notes—Security.” The security interests in the Collateral securing the Notes may be released under certain circumstances, including without your consent or the consent of the trustee of the Notes. See “Risk Factors—Risks Related to the Collateral,” “Description of the Notes—Security Documents” and “Description of the Notes—Release of Collateral.”

 

Intercreditor Agreements

The Exchange Notes will be subject to an intercreditor agreement (the “Senior Lien Intercreditor Agreement”) that will establish the subordination of the liens on the Collateral securing the Notes and the related guarantees to the liens on the Collateral securing first-priority lien obligations, including the Bank Credit Facility, and certain other matters relating to the administration of security interests.

 

  The terms of the Senior Lien Intercreditor Agreement are set forth under “Description of the Notes—Security Documents—Senior Lien Intercreditor Agreement.”

 

Optional Redemption

Prior to May 10, 2019, we may redeem some or all of the Notes at a redemption price equal to 100% of the principal amount of the Notes plus accrued and unpaid interest, if any, to (but not including) the applicable redemption date plus the applicable “make-whole” premium. On or after May 10, 2019, we may redeem some or all of the Notes at the redemption prices set forth in this prospectus. Additionally, on or prior to May 10, 2019, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of specified equity offerings at the redemption price set forth in this prospectus. See “Description of the Notes—Optional Redemption.”

 

Change of Control

Upon certain events constituting a change of control under the indenture, the Issuers will be required to make an offer to purchase



 

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the Notes at a price equal to 101% of their principal amount, plus accrued and unpaid interest, if any, to, but not including, the date of the purchase. See “Description of the Notes—Change of Control.”

 

Certain Covenants

The indenture governing the Notes, among other things, limits the ability of the Issuers and the ability of their restricted subsidiaries to:

 

   

incur or guarantee additional indebtedness;

 

   

pay dividends or distributions on, or redeem or repurchase, capital stock and make other restricted payments;

 

   

make investments;

 

   

consummate certain asset sales;

 

   

engage in transactions with affiliates;

 

   

grant or assume liens; and

 

   

consolidate, merge or transfer all or substantially all of their assets.

 

  These limitations are subject to a number of important qualifications and exceptions as described under “Description of the Notes—Certain Covenants.” One or more parent entities of Holdings are not subject to any of the covenants in the indenture governing the Notes.

 

  In addition, certain of the covenants will be suspended if both Moody’s Investors Service, Inc. and S&P Global Ratings assign the Notes an investment grade rating in the future and certain other conditions are met. See “Description of the Notes—Certain Covenants.” In the event that the Issuers and their restricted subsidiaries are not subject to such covenants for any period of time as a result of the preceding sentence and, on any subsequent date, one or both of such rating agencies withdraws or downgrades the ratings assigned to the Notes to sub-investment grade, then the Issuers and their restricted subsidiaries will thereafter again be subject to such covenants.

 

Use of Proceeds

We will not receive any proceeds from the issuance of the Exchange Notes in exchange for the outstanding Initial Notes. We are making this exchange solely to satisfy our obligations under the Registration Rights Agreement. See “Use of Proceeds.”

 

Absence of a Public Market for the Exchange Notes

The Exchange Notes are new securities for which there is no established market. As such, we cannot assure you that a market for these Exchange Notes will develop or that this market will be liquid. We do not intend to apply for a listing of the Exchange Notes on any securities exchange or any automated dealer quotation system. Please refer to the section of this prospectus entitled “Risk Factors—Risks Related to the Exchange Offer—There is no active trading market for the Exchange Notes.”


 

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Risk Factors

Investment in the Exchange Notes involves certain risks. You should carefully consider the information under “Risk Factors” and all other information included in this prospectus before investing in the Exchange Notes.

 

Form of the Exchange Notes

The Exchange Notes will be represented by one or more permanent global securities in registered form deposited on behalf of The Depository Trust Company (“DTC”) with Wilmington Trust, National Association, as custodian. You will not receive Exchange Notes in certificated form unless one of the events described in the section of this prospectus entitled “Description of the Notes—Book Entry; Delivery and Form—Exchange of Book Entry Notes for Certificated Notes” occurs. Instead, beneficial interests in the Exchange Notes will be shown on, and transfers of these Exchange Notes will be effected only through, records maintained in book-entry form by DTC with respect to its participants.


 

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RISK FACTORS

You should carefully consider the risk factors set forth below, as well as the other information contained in this prospectus, before deciding to tender your Initial Notes and participate in the Exchange Offer. Any of the following risks could materially and adversely affect our business, prospects, results of operations, financial condition and/or cash flows. In addition, the risks described below and elsewhere in this prospectus are not the only risks that we face. Additional risks and uncertainties not currently known to us or those that we currently view to be immaterial could also materially and adversely affect our business, prospects, results of operations, financial condition and/or cash flows. In any such case, you may lose all or a part of your investment in the Notes.

Risks Related to the Company

The integration of Stone and Talos Energy LLC will present challenges that may result in a decline in the anticipated benefits of the Stone Combination.

The Stone Combination involved the combination of two businesses that historically operated as independent businesses, and we will be required to continue to devote management attention and resources to integrating our business practices and operations. We could be adversely affected by the diversion of management’s attention, the loss of key employees and skilled workers, and any delays or difficulties encountered in connection with this integration process. If we experience difficulties with the integration process, the anticipated benefits of the Stone Combination may not be realized fully or at all, or may take longer to realize than expected. These integration matters could have an adverse effect on our business, results of operations, financial condition or prospects for an undetermined period of time.

The market price of our common stock may decline as a result of the Stone Combination.

The market price of our common stock may decline as a result of the Stone Combination if, among other things, we are unable to achieve the expected benefits of the transaction, or if the transaction costs related to the Stone Combination and integration are greater than expected. The market price also may decline if we do not achieve the perceived benefits of the Stone Combination as rapidly or to the extent anticipated by financial or industry analysts or if the effect of the Stone Combination on our financial results is not consistent with the expectations of financial or industry analysts.

We are controlled by Apollo Funds and Riverstone Funds. The interests of Apollo Funds and Riverstone Funds may differ from the interests of our other stockholders.

Immediately following the closing of the Stone Combination, the stakeholders of Talos Energy LLC beneficially owned and possessed voting power over 63% of our common stock. Under the Stockholders’ Agreement, dated as of May 10, 2018, among certain Apollo Funds, certain Riverstone Funds and the Company (the “Stockholders’ Agreement”), the Apollo Funds and the Riverstone Funds may acquire additional shares of our common stock without the approval of the Company Independent Directors.

Through their ownership of a majority of our voting power and the provisions set forth in our charter, bylaws and the Stockholders’ Agreement, the Apollo Funds and the Riverstone Funds have the ability to designate and elect a majority of our directors. As a result of the Apollo Funds’ and the Riverstone Funds’ ownership of a majority of the voting power of our common stock, we are a “controlled company” as defined in New York Stock Exchange (“NYSE”) listing rules and, therefore, we are not be subject to NYSE requirements that would otherwise require us to have (i) a majority of independent directors and (ii) nominating and compensation committees composed solely of independent directors. We have elected not to take advantage of the “controlled company” exemptions available to us, but we may do so in the future. Under the Stockholders’ Agreement, our board of directors has five directors not designated by the Apollo Funds and the Riverstone Funds and five directors designated by the Apollo Funds and the Riverstone Funds.

 

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Apollo Funds and Riverstone Funds also have control over all other matters submitted to stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and corporate governance, subject to the terms of the Stockholders’ Agreement that require the Apollo Funds and the Riverstone Funds to vote in a specified manner on certain actions, including their agreement to vote in favor of director nominees not designated by the Apollo Funds and the Riverstone Funds. Apollo Management and Riverstone may have different interests than other holders of our common stock and may make decisions adverse to your interests.

Among other things, Apollo Funds’ and Riverstone Funds’ control could delay, defer, or prevent a sale of us that our other stockholders support, or, conversely, this control could result in the consummation of such a transaction that other stockholders do not support. This concentrated control could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

We will continue to incur, transaction-related and restructuring costs in connection with the Stone Combination and the integration of the two businesses.

We will continue to incur, transaction-related and restructuring costs in connection with the Stone Combination and the integration of the businesses of Stone and Talos Energy. These expenses could, particularly in the near term, reduce the expected pre-tax synergies related to the integration of the businesses following the completion of the Stone Combination, and accordingly, any net synergies may not be achieved in the near term or at all. These integration expenses may result in us taking significant charges against earnings following the completion of the Stone Combination.

The corporate opportunity provisions in our charter could enable others to benefit from corporate opportunities that might otherwise be available to us.

Subject to the limitations of applicable law, our charter, among other things:

 

   

permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

 

   

permits the Apollo Funds, the Riverstone Funds, and any of our officers or directors who is also an officer, director, employee, managing director, or other affiliate of the Apollo Funds or the Riverstone Funds to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

 

   

provides that if the Apollo Funds, the Riverstone Funds, or any of our officers or directors who is also an officer, director, employee, managing director, or other affiliate of the Apollo Funds or the Riverstone Funds becomes aware of a potential business opportunity, transaction, or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others.

 

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Our charter designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees, or agents.

Our charter provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents or stockholders (including a beneficial owner of stock) to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law, our charter or bylaws, or (iv) any action asserting a claim governed by the internal affairs doctrine, in each case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as defendants in the case. Any person or entity purchasing or otherwise acquiring any interest in any share of our capital stock will be deemed to have notice of and consent to these provisions of our charter. This exclusive forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our charter inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition, or results of operations.

The Apollo Funds and the Riverstone Funds are prohibited from transferring shares of our common stock until the first anniversary of the Closing Date, after which, subject to restrictions, they will be permitted to transfer their shares of our common stock, which could have a negative impact on our stock price.

For 12 months following the completion of the Stone Combination, the Apollo Funds and the Riverstone Funds are prohibited from transferring their shares of our common stock other than to their respective affiliates, unless such transfer is approved by a majority of the Company Independent Directors. The lockup will cease to apply to 50% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the six-month anniversary of the Closing Date and will cease to apply to an additional 25% of our common stock that was issued to the Apollo Funds and the Riverstone Funds, respectively, at the closing of the Stone Combination on the nine-month anniversary of the Closing Date. Following such 12-month lockup period, the Apollo Funds and the Riverstone Funds will be permitted, subject to certain restrictions, to transfer shares of our common stock, including in public offerings pursuant to registration rights granted by us. Any such transfer could significantly increase the number of shares of our common stock available in the market, which could cause a decrease in the price of our common stock.

Additionally, pursuant to the Stockholders’ Agreement, until the first anniversary of the Closing Date, each of the Apollo Funds and the Riverstone Funds will be prohibited from transferring any shares of our common stock in any transaction that would result in the transferee owning more than 35% of the outstanding shares of our common stock without the prior approval of a majority of the Company Independent Directors, unless such transferee agrees in writing to be bound by substantially the same provisions as the stockholders are bound by pursuant to the Stockholders’ Agreement. Following the first anniversary of the Closing Date, the Apollo Funds and the Riverstone Funds could sell a significant percentage of our common stock to a third party that is not subject to provisions similar to the provisions in the Stockholders’ Agreement.

Oil and natural gas prices are volatile. Significant declines in commodity prices in the future may adversely affect our financial condition and results of operations, cash flows, access to the capital markets, and ability to grow.

Our revenues, cash flows, profitability, and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to

 

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access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves, and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Oil and natural gas prices significantly declined in the second half of 2014, with sustained lower prices continuing throughout 2015, 2016 and 2017. Despite a modest recovery in late 2017, commodity prices could remain suppressed or decline further in the future, which will likely have material adverse effects on our proved reserves and borrowing base. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, which is impacted by declining prices. Significant price declines could cause us to take ceiling test write-downs, which would be reflected as non-cash charges against current earnings. See the Risk Factor entitled “—Lower oil and natural gas prices and other factors in the future may result in ceiling test write-downs and other impairments of our asset carrying values” for further discussion.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can produce economically. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2015 through June 30, 2018, the NYMEX West Texas Intermediate (“WTI”) crude oil price per Bbl ranged from a low of $30.62 to a high of $69.98, and the NYMEX natural gas price per MMBtu ranged from a low of $1.71 to a high of $3.93. The high, low and average prices for NYMEX WTI and NYMEX Henry Hub are monthly contract prices. The prices we receive for our oil and natural gas depends upon many factors beyond our control, including, among others:

 

   

changes in the supply of and demand for oil and natural gas;

 

   

market uncertainty;

 

   

level of consumer product demands;

 

   

hurricanes and other adverse weather conditions;

 

   

domestic and foreign governmental regulations and taxes;

 

   

price and availability of alternative fuels;

 

   

political and economic conditions in oil-producing countries, particularly those in the Middle East, Russia, South America and Africa;

 

   

actions by the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil and natural gas price and production controls;

 

   

U.S. and foreign supply of oil and natural gas;

 

   

price and quantity of oil and natural gas imports and exports;

 

   

the level of global oil and natural gas exploration and production;

 

   

the level of global oil and natural gas inventories;

 

   

localized supply and demand fundamentals and transportation availability;

 

   

speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

 

   

price and availability of competitors’ supplies of oil and natural gas;

 

   

technological advances affecting energy consumption; and

 

   

overall domestic and foreign economic conditions.

 

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These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other.

We are required to meet a minimum work program expressed in work units during a four-year exploration period according to one of our PSCs with the National Hydrocarbons Commission of Mexico (the “CNH”).

On September 4, 2015, our subsidiary Talos Energy LLC, together with its consortium partners Sierra Oil & Gas S. de R.L de C.V. (“Sierra”) and Premier Oil Plc (“Premier” and, together with Talos Energy and Sierra, the “Consortium”) executed two PSCs with the CNH for the development of the Mexican acreage—one for each of Blocks 2 and 7. PSCs require that the Consortium execute a minimum work program expressed in work units during a four-year exploration period. The work units represent the performance of exploration studies and seismic and drilling activities. The aggregate value of the minimum work program under the PSCs is approximately $143.0 million (gross), of which we are responsible for a pro rata portion based on our participation interest—35% in Block 7 and 45% in Block 2. In order to guarantee the execution of the minimum work program under the PSCs, the Consortium was required to post a financial guarantee to the CNH of approximately $143 million (gross), of which Talos Energy’s share was $48.7 million. We satisfied our share through a performance bond. As the Consortium completes the minimum work program under the PSCs, the amount of the financial guarantee will be reduced accordingly beginning after the second anniversary of entering into the PSCs. Effective January 23, 2018, the activities already performed on Block 7 have satisfied the minimum work program on Block 7, reducing the $143 million (gross) in outstanding letters of credit by $65.7 million (gross). Activities on Block 2 are in the planning phase and the Consortium is on schedule to satisfy the minimum work program on Block 2 by September 4, 2019. If the Consortium is unable to meet the minimum work program, we could be liable along with the other members in the Consortium for the remaining financial guarantee, and the CNH could rescind the Block 2 PSC for a default.

Regulatory requirements and permitting procedures imposed by the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”) could significantly delay our ability to obtain permits to drill new wells in offshore waters.

BSEE and BOEM have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. Compliance with these added and more stringent regulatory requirements and with existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response, and decommissioning plans and possible additional regulatory initiatives could result in difficult and more costly actions and 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 continuing to develop and implement new, more restrictive requirements. For example, in April 2016, BSEE published a final rule on well control that, among other things, imposes rigorous standards relating to the design, operation, and maintenance of blow-out preventers, real-time monitoring of deepwater and high temperature, high pressure drilling activities, and enhanced reporting requirements. Pursuant to President Trump’s Executive Orders dated March 28, 2017, and April 28, 2017 (the “Executive Orders”), respectively, BSEE initiated a review of the well control regulations to determine whether the rules are consistent with the stated policy of encouraging energy exploration and production, while ensuring that any such activity is safe and environmentally responsible. One consequence of this review is that on December 29, 2017, the BSEE published proposed revisions to its regulations regarding offshore drilling safety equipment, which proposal includes the removal of the requirement for offshore operators to certify through an independent third party that their critical safety and pollution prevention equipment (e.g., subsea safety equipment, including blowout preventers) is operational and functioning as designed in the most extreme conditions. The December 2017 proposed rule has not been finalized and there remains substantial uncertainty as to the scope and extent of any revisions to existing oil and gas safety

 

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and performance-related regulations and other regulatory initiatives that ultimately will be adopted by BSEE pursuant to its review process.

Also, in April 2016, BOEM published a proposed rule that would update existing air emissions requirements relating to offshore oil and natural gas activity on the Outer Continental Shelf (“OCS”). BOEM regulates these air emissions in connection with its review of exploration and development plans, rights of way and rights of use, and/or easement applications. The proposed rule would bolster existing air emissions requirements by, among other things, requiring the reporting and tracking of the emissions of all pollutants defined by the U.S. Environmental Protection Agency (the “EPA”) to affect human health and public welfare. Pursuant to the Executive Orders, BOEM has ceased rulemaking activities for and is reviewing the proposed air quality rule. On October 24, 2017, the Department of the Interior announced that it is currently reviewing recommendations on how to proceed, including promulgating final rules for certain necessary provisions and issuing a new proposed rule that may withdraw certain provisions and seek additional input on others.

Compliance with new and future regulations could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Furthermore, among other adverse impacts, to the extent that the BOEM and BSEE do not reduce the stringency of existing oil and gas safety and performance-related regulations and other regulatory initiatives, the regulatory requirements imposed by such existing or future, more stringent regulations or other regulatory initiatives could delay operations, disrupt our operations, or increase the risk of leases expiring before exploration and development efforts have been completed due to the time required to develop new technology. Additionally, if left unchanged, the existing, or future, more stringent oil and gas safety and performance-related regulations and other regulatory initiatives imposed by the BOEM and BSEE could result in increased financial assurance requirements and incurrence of associated added costs, limit operational activities in certain areas, or cause us to incur penalties or shut-in production at one or more of our facilities. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect 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, any of which could have a material adverse effect on our business. We cannot predict with any certainty 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.

New guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS may have a material adverse effect on our business, financial condition, or results of operations.

The BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In July 2016, the BOEM issued Notice to Lessees and Operators (“NTL”) #2016-N01 (the “2016 NTL”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROW”) and rights of use and easement (“RUEs”). The 2016 NTL became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementing this NTL so as to provide the BOEM with time to review its complex financial assurance program.

In December 2016, we received an order to provide additional security from BOEM totaling approximately $0.5 million for our sole liability properties (the “December 2016 Order”). However, following the BOEM’s action in January 2017 to extend the implementation date of the 2016 NTL for a period of six months, the BOEM elected to include sole liability properties as being covered under the extension and thus rescinded the December 2016 Order while BOEM reviewed the financial assurance program. In June 2017, the BOEM further extended the start date for implementing the 2016 NTL indefinitely beyond June 30, 2017. This extension currently remains in effect; however, the BOEM reserved the right to re-issue sole liability orders in the future, including

 

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in the event that it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning sole liabilities.

As of the filing date of this prospectus, we are in compliance with our financial assurance obligations to the BOEM and have no outstanding BOEM orders for financial assurance obligations. Following completion of its review, the BOEM may elect to retain the 2016 NTL in its current form or may make revisions thereto and, thus, until the review is completed and BOEM determines what additional financial assurance may be required by us, we cannot provide any assurance that such financial assurance coverage can be obtained. Moreover, the BOEM could in the future make other demands for additional financial assurances covering our obligations under sole liability properties and/or our non-sole liability properties. The BOEM may reject our proposals and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of the BOEM to provide additional surety bonds or other financial assurances, the BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition.

In addition, if fully implemented, the new 2016 NTL is likely to result in the loss of supplemental bonding waivers for a large number of operators on the OCS, which in turn force these operators to seek additional surety bonds and could, consequently, challenge the surety bond market’s capacity for providing such additional financial assurance. Operators who have already leveraged their assets as a result of the declining oil market could face difficulty obtaining surety bonds because of concerns the surety companies may have about the priority of their lien on the operator’s collateral. Moreover, depressed oil prices could result in sureties seeking additional collateral to support existing bonds, such as cash or letters of credit, and we cannot provide assurance that we are able to satisfy collateral demands for future bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations and consequently have a material adverse effect on our business and results of operations.

We have a subsidiary that is subject to a plea agreement with the Department of Justice (“DOJ”) pursuant to which certain exploration and production activities must comply with a Safety and Environmental Compliance Program (“SECP”). Noncompliance with the SECP could result in a violation of the plea agreement and provide a basis for revocation or modification of probation.

In February 2014, we received a grand jury subpoena from the DOJ addressing activities that occurred on the Ship Shoal 225A production platform operated by one of our subsidiaries, Energy Resource Technology GOM, LLC (“ERT”), which was subsequently renamed Talos ERT LLC. On November 30, 2015, ERT was charged with two violations of the Outer Continental Shelf Lands Act in connection with hot work and blowout preventer testing activities, and with two violations of the Clean Water Act for self-reported activities surrounding overboard discharge sampling and unpermitted discharges. On January 6, 2016, ERT pled guilty to these charges. On April 6, 2016, the United States District Court for the Eastern District of Louisiana (the “Court”) accepted ERT’s plea and sentenced ERT, consistent with the plea agreement, to pay a penalty of $4.2 million, which ERT has paid. The Court placed ERT on probation for three years. The conditions of probation include compliance with an agreed SECP, pursuant to which ERT and another subsidiary of ours must implement enhanced safety and environmental compliance inspections, reviews and audits, implement a comprehensive training program, implement enhanced operational controls to better manage, detect and prevent safety and environmental violations, and preparation and implementation of schedule for decommissioning. We believe that we are in substantial compliance with the SECP, a failure to comply with the SECP could result in a

 

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violation of the plea agreement and provide a basis for revocation or modification of probation, which could adversely our financial condition and operations.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. However, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in its borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations. In addition, we may face limitations on our ability to access the debt and equity capital markets and complete asset sales, an increased counterparty credit risk on our derivatives contracts, and the requirement by our contractual counterparties to post collateral guaranteeing performance.

We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital is subject to a number of variables, including:

 

   

our proved reserves;

 

   

the level of hydrocarbons we are able to produce from our wells;

 

   

the prices at which our production is sold;

 

   

our ability to acquire, locate, and produce new reserves; and

 

   

our ability to borrow under our Bank Credit Facility.

If low oil and natural gas prices, operating difficulties, declines in reserves, or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been significantly limited since the significant decline in commodity prices since mid-2014.

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.

Our production, revenue, and cash flow from operating activities are derived from assets that are concentrated in a single geographic area, the Gulf of Mexico. Unlike other entities that are geographically

 

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diversified, we may not have the resources to effectively diversify our operations or benefit from the possible spreading of risks or offsetting of losses. Our lack of diversification may subject us to numerous economic, competitive, and regulatory developments, any or all of which may have an adverse impact upon the particular industry in which we operate, and result in our dependency upon a single or limited number of hydrocarbon basins. In addition, the geographic concentration of our properties in the Gulf of Mexico and the 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 or capacity to transport, gather, or process production;

 

   

changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

 

   

extensive governmental regulation (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and plugging and abandonment (“P&A”) costs) and interruption or termination of operations by governmental authorities based on environmental, safety, or other considerations; and/or

 

   

changes in the regulatory environment such as the new guidelines recently issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS.

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may 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.

We may experience significant shut-ins and losses of production due to the effects of hurricanes in the Gulf of Mexico.

Our production is primarily associated with our properties in the Gulf of Mexico and the Gulf Coast. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes and tropical storms in the Gulf of Mexico. We are unable to predict what impact future hurricanes and tropical storms might have on our future results of operations and production.

A significant portion of our production, revenue and cash flow is concentrated in our Phoenix Field. Because of this concentration, any production problems, impacts of adverse weather or inaccuracies in reserve estimates could have a material adverse impact on our business.

For the six months ended June 30, 2018, approximately 51% of our production and 63% of our oil, natural gas, and NGL revenue was attributable to our Phoenix Field, which is located offshore Louisiana. This concentration in the Phoenix Field means that any impact on our production from the Phoenix Field, whether because of mechanical problems, adverse weather, well containment activities, changes in the regulatory environment, or otherwise, could have a material effect on our business. We produce the Phoenix Field through the Helix Producer I (“HP-I”) a dynamically positioned floating production facility that is operated by Helix Energy Solutions Group, Inc. (“Helix”). The HP-I interconnects the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. Because the HP-I may have to be disconnected from the Phoenix Field if circumstances require, our production from the Phoenix Field may be subject to more frequent interruptions than if the Phoenix Field was produced by a more conventional platform. Such disconnects have occurred in the past but have not materially impacted our production, but there can be no assurance a disconnect will not occur that could materially impact our production. We are also required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the United States Coast

 

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Guard, during which time we are unable to produce the Phoenix Field. On September 10, 2016, the HP-I was disconnected from the production buoy and released for dry dock for 28 days. Upon completion of the dry dock, the HP-I remained disconnected from the buoy connecting it to the Phoenix Field due to Federal Emergency Management Agency testing of test upgrades to the power management system, preventing us from reconnecting the HP-I to the Phoenix Field for a further five days. Once the buoy was connected, Phoenix Field production remained shut-in for an additional five days to conduct buoy remediation of the swivel piping. In addition, for 25 days in March 2015, we were required to disconnect the HP-I from the production buoy due to upgrades to the power management system of the vessel, which is an integral part of the dynamic positioning system. The upgrade work was followed by sea trials that tested the dynamic positioning system and were required by various regulatory groups, including the United States Coast Guard.

The HP-I is part of the Helix Well Containment Group (“HWCG”), which is a consortium that is available to respond to any deepwater well control event, such as the Macondo well oil spill. If such an event were to occur and the HWCG was to be utilized for well control, the HP-I, which is the vessel that would be used to respond to the deepwater well control event, would be required to disconnect from the Phoenix Field until such time as the well control event was resolved and the HP-I could return to the Phoenix Field. During such time period, we would not be able to produce the Phoenix Field. In the event the HP-I has to disconnect from the Phoenix Field, our production, revenue, and cash flow could be adversely affected, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

In addition, all of our production from the Phoenix Field flows through the Boxer facility operated by Shell Pipeline Company LP. To the extent Shell Pipeline Company LP temporarily shuts in its Boxer facility, whether for maintenance or otherwise, we would not able to produce the Phoenix Field during this period of time, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.

If the actual reserves associated with the Phoenix Field are less than our estimated reserves, such a reduction of reserves could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named Gulf of Mexico windstorm, oil pollution, construction all risk, workers’ compensation and employers’ liability, and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses.

We are expected to have general liability insurance coverage with an annual aggregate limit of $500 million. We selectively purchase physical damage insurance coverage for our pipelines, platforms, facilities, and umbilicals for losses resulting from named windstorms and operational activities.

Our operational control of well coverage is expected to provide limits that vary by well location and depth and range from a combined single limit of $25 million to $500 million per occurrence. Exploratory deepwater wells have a coverage limit of up to $500 million per occurrence. Additionally, we maintain up to $150 million in oil pollution liability coverage. Our operational control of well and physical damage policy limits is scaled proportionately to our working interests. Our general liability program utilizes a combination of assured’s interest and scalable limits. All of our policies described above are subject to deductibles, sub-limits, or self-insurance. Under our service agreements, including drilling contracts, we expect to be indemnified for injuries and death of the service provider’s employees as well as contractors and subcontractors hired by the service provider subject to the application of various states’ laws.

 

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An operational (including a well control event) or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

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

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

We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, we compare, at the end of each financial reporting period for each cost center, the present value of estimated future net cash flows from proved reserves (based on a trailing 12-month average, hedge-adjusted commodity price and excluding cash flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas properties, net of related deferred taxes. We refer to this comparison as a ceiling test. If the net capitalized costs of proved oil and gas properties exceed the estimated discounted future net cash flows from proved reserves, we are required to write down the value of our oil and gas properties to the value of the estimated discounted future net cash flows. A write-down of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to write-down the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our oil and gas operations are subject to various international and U.S. federal, state and local governmental regulations that materially affects our operations.

Our oil and gas operations are subject to various international and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials into the environment; bonds or other financial responsibility requirements to cover drilling contingencies and well plugging and abandonment and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

 

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In July 2017, we, along with partners Sierra and Premier, reported the discovery of a significant reservoir of crude oil in the Sureste basin offshore Mexico through the Zama-1 well. Data from the Zama-1 well indicates that it is possible the deposit could be part of a field that extends into an exploration block in which the state entity Pemex holds exploration and development rights.

The Ministry of Energy of Mexico has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir.

Even with the final regulations in place, there are still some uncertainties regarding the unitization process, including the selection of a unit operator and the exact length of time that will take to obtain approvals of any unit agreements. Any unit operating agreement eventually reached by relevant parties or any unit order issued by a governmental entity in Mexico could be adverse to us and affect the value that we are able to recognize from the reservoir discovery, including but not limited to an agreement or unit order that would require us to allow a third party to develop and produce the crude oil reservoir identified through the Zama-1 well.

In addition, the Oil Pollution Act of 1990 (“OPA”) requires operators of U.S. offshore facilities to prove that they have the financial capability to respond to costs that may be incurred in connection with potential oil spills. Under the OPA and other environmental statutes such as the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”) and analogous state laws, owners and operators of certain defined onshore and offshore facilities are strictly liable for spills of oil and other regulated substances, subject to certain limitations. Consequently, a spill from one of our facilities subject to laws such as the OPA, CERCLA and RCRA could require the expenditure of additional, and potentially significant, amounts of capital, or could have a material adverse effect on our earnings, results of operations, competitive position or financial condition. We cannot predict the ultimate cost of compliance with these requirements or their impact on our earnings, operations or competitive position.

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.

The vast majority of our 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. Our future oil and natural gas production is highly dependent upon our level of success in finding or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. 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. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and they have lowered the level of activity and depressed values in the oil and natural gas property sales market.

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

Estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and

 

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assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. Additionally, our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. 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.

You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2017 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues are affected by factors such as:

 

   

the amount and timing of capital expenditures and decommissioning costs;

 

   

the rate and timing of production;

 

   

changes in governmental regulations or taxation;

 

   

volume, pricing and duration of our oil and natural gas hedging contracts;

 

   

supply of and demand for oil and natural gas;

 

   

actual prices we receive for oil and natural gas; and

 

   

our actual operating costs in producing oil and natural gas.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.

At June 30, 2018, approximately 31% of our estimated proved reserves (by volume) were undeveloped and approximately 23% were non-producing. Any or all of our proved undeveloped or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present produces in economic quantities.

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and

 

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do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement may limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Our acreage has to be drilled before lease expiration in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Unless production is established as required by the leases covering the undeveloped acres, the leases for such acreage may expire. As of June 30, 2018, we had leases on 20,860 gross (20,775 net) acres that could potentially expire during the remainder of the 2018 fiscal year.

Our drilling plans for areas not 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 the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those sections.

The marketability of our production depends mostly upon the availability, proximity, and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, proximity, operation, and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of these gathering systems, pipelines and processing facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and natural gas production and transportation, general economic conditions, and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors changed dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represents a significant risk.

Our actual production could differ materially from our forecasts.

From time to time, we may provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects, or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

 

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Our operations are subject to numerous risks of oil and natural gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the Gulf of Mexico deepwater and/or in the Gulf Coast deep gas, our drilling activities increases capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed, or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in formations;

 

   

equipment failures or accidents;

 

   

hurricanes and other adverse weather conditions;

 

   

shortages in experienced labor; and

 

   

shortages or delays in the delivery of equipment.

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment, and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

Our industry experiences numerous operating risks.

The exploration, development and production of oil and gas properties involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, abnormally pressured formations and environmental hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures or discharges of toxic gases. We are also involved in completion operations that utilize hydraulic fracturing, which may potentially present additional operational and environmental risks. Additionally, our offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions, including the effects of hurricanes.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

Our business is also subject to the risks and uncertainties normally associated with the exploration for and development and production of oil and natural gas that are beyond our control, including uncertainties as to the presence, size and recoverability of hydrocarbons. We may not encounter commercially productive oil and natural gas reservoirs. We may not recover all or any portion of our investment in new wells. The presence of unanticipated pressures or irregularities in formations, miscalculations or accidents may cause our drilling activities to be unsuccessful and/or result in a total loss of our investment, which could have a material adverse effect on our financial condition, results of operations and cash flows. In addition, we may be uncertain as to the future cost or timing of drilling, completing and operating wells.

We have an interest in six deepwater fields: the Phoenix Field, the Bushwood Field, the Gunnison Field, the Pompano Field, the Amberjack Field and the Ram Powell Field, and may attempt to pursue additional

 

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operational activity in the future and acquire additional fields and leases in the deepwaters of the Gulf of Mexico. 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 Gulf of Mexico Conventional Shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. 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 Gulf of Mexico Conventional 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.

If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations. Any of these industry operating risks could have a material adverse effect on our business, results of operations, and financial condition.

Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks, and other disruptions.

As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure, or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability.

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our future financial position and results of operations.

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 operations. These costs are typically

 

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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 Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs 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 estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

Moreover, the timing for pursuing restoration and removal activities has accelerated for operators in the Gulf of Mexico following BSEE’s issuance of an NTL that established a more stringent regimen for the timely decommissioning of what is known as “idle iron” wells, which are platforms and pipelines that are no longer producing or serving exploration or support functions with respect to an operator’s lease in the Gulf of Mexico. The idle iron NTL requires decommissioning of any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities, which must then be permanently plugged or temporarily abandoned within three years’ time. Similarly, platforms or other facilities no longer useful for operations must be removed within five years of the cessation of operations. We may have to draw on funds from other sources to satisfy decommissioning 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. Moreover, as a result of the implementation of the idle iron NTL, there is expected to be increased demand for salvage contractors and equipment operating in the Gulf of Mexico, resulting in increased estimates of plugging, abandonment, and removal costs and associated increases in operators’ asset retirement obligations.

In addition, we could become responsible for decommissioning liabilities related to offshore facilities we no longer own or operate. Federal regulations allow the government to call upon predecessors in interest of oil and natural gas leases to pay for plugging, abandonment, restoration, and decommissioning obligations if the current operator fails to fulfill those obligations and regardless of any indemnification agreements, the costs of which could be significant. Moreover, several onshore and offshore exploration and production companies have sought bankruptcy protection over the past several years. The government may seek to impose a bankrupt entity’s plugging and abandonment obligations on us or other predecessors-in-interest, which could be significant and adversely affect our business, results of operations, financial condition and cash flows.

We may not receive payment for a portion of our future production.

We may not receive payment for a portion of our future production. We attempt to diversify our sales and obtain credit protections, such as parent guarantees, from certain of our purchasers. The tightening of credit in the financial markets may make it more difficult for customers to obtain financing and, depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by customers. We are unable to predict what impact the financial difficulties of certain purchasers may have on our future results of operations and liquidity.

We may not realize all of the anticipated benefits from our future acquisitions, and we may be unable to successfully integrate future acquisitions.

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by

 

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expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our 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, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates, and fluctuations in market prices.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties 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 regular business concerns;

 

   

diverting financial resources away from existing operations;

 

   

increasing our indebtedness; and

 

   

incurring potential environmental or regulatory liabilities and title problems.

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of or loss of momentum in the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our 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.

Our future acquisitions could expose us to potentially significant liabilities, including plugging and abandonment liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs, and potential environmental, regulatory and other liabilities, including plugging and abandonment liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with its assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

There may be threatened, contemplated, asserted, or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation, or other matters of which we are unaware, which could materially and adversely affect our production, revenues, and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues, and results of operations.

 

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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act (the “FCPA”).

We are subject to the FCPA and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We may do business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

Under the PSCs with the CNH, we work as a consortium with two other partners—Sierra and Premier. Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the CNH has the authority to rescind the PSCs if these violations occur.

Our operations may be adversely affected by political and economic circumstances in the countries in which we operate.

Our oil and gas exploration, development, and production activities are subject to political and economic uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities, and other political risks, including tension and confrontations among political parties. Some of these risks may be higher in the developing countries in which we conduct our activities, namely, Mexico. Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. The President-elect, Andrés Manuel López Obrador, will take office on December 1, 2018, and his political party, Movimiento Regeneración Nacional will have a majority in both houses of Mexico’s congress. Mr. Lopez Obrador, and certain members of his cabinet have, in the past, made statements that would call into question the degree of support their administration will have for Mexico’s energy reforms. However, at this time we cannot predict what changes (if any) will result from this change in administration. Political events in Mexico could adversely affect economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial position.

Our operations may be exposed to risks of illegal cartel activities, local economic conditions, political disruption, and governmental policies that may:

 

   

disrupt our operations;

 

   

restrict the movement of funds or limit repatriation of profits;

 

   

in the case of our non-U.S. operations, lead to U.S. government or international sanctions; and

 

   

limit access to markets for periods of time.

Disruptions may occur in the future, and losses caused by these disruptions may not be covered by insurance. Consequently, our exploration, development, and production activities may be substantially affected by factors that could have a material adverse effect on our financial condition and results of operations. Furthermore, in the event of a dispute arising from non-U.S. operations, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute.

Our operations are adversely affected by laws and policies of the jurisdictions, including Mexico, the United States, the Netherlands and other jurisdictions, in which we do business that affect foreign trade and

 

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taxation. Changes in any of these laws or policies or the implementation thereof could have a material adverse effect on our results of operations and financial position.

New technologies may cause our current exploration and drilling methods to become obsolete, and we may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and that may in the future allow them to implement new technologies before we can. We rely heavily on the use of seismic technology to identify low-risk development and exploitation opportunities and to reduce our geological risk. Seismic technology or other technologies that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our business, results of operations and financial condition may be materially adversely affected.

We may not be in a position to control the timing of development efforts, the associated costs, or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. We may have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners and our limited ability to influence operations and associated costs of properties operated by others could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depends upon a number of factors that could 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;

 

   

risk of other non-operator’s failing to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;

 

   

selection of technology;

 

   

the rate of production of the reserves; and

 

   

the timing and cost of P&A operations.

In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

 

   

refuse to initiate exploration or development projects;

 

   

initiate exploration or development projects on a slower or faster schedule than we would prefer;

 

   

delay the pace of exploratory drilling or development; and/or

 

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drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Competition within our industry may adversely affect our operations.

Competition within our industry is intense, particularly with respect to the acquisition of producing properties and undeveloped acreage. We compete with major oil and gas companies and other independent producers of varying sizes, all of which are engaged in the acquisition of properties and the exploration and development of such properties. Many of our competitors have financial resources and exploration and development budgets that are substantially greater than our budget, which may adversely affect our ability to compete. If other companies relocate to the Gulf of Mexico region, levels of competition may increase and our business could be adversely affected. In the exploration and production business, some of the larger integrated companies may be better able than we are to respond to industry changes including price fluctuations, oil and gas demand, political change and government regulations.

We actively compete with other companies when acquiring new leases or oil and gas properties. For example, new leases acquired from 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 impacts attaining success in the industry. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted.

The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations.

We have a limited number of customers that provide a substantial portion of our revenue. The loss of our larger customers, including Shell Trading (US) Company, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations.

Our business depends on access to oil and natural gas processing, gathering and transportation systems and facilities.

The marketability of our oil and natural gas production depends in large part on the operation, availability, proximity, capacity and expansion of processing, gathering and transportation facilities owned by third parties. We can provide no assurance that sufficient processing, gathering and/or transportation capacity exists or that we will be able to obtain sufficient processing, gathering and/or transportation capacity on economic terms. A lack of available capacity on processing, gathering and transportation facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these facilities for an extended period of time could negatively impact our revenues. In addition, we enter into contracts for firm transportation, and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above. In addition, the rates charged for processing, gathering and transportation services may increase over time.

 

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The loss of key personnel could adversely affect our ability to operate.

Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to handle all aspects of our exploration, production and decommissioning activities. The demand for skilled workers in our industry is high, and the supply is limited. A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

Resolution of litigation could materially affect our financial position and results of operations.

Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods.

Future regulations relating to and interpretations of recently enacted U.S. federal income tax legislation may vary from our current interpretation of such legislation.

The U.S. federal income tax legislation recently enacted in Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act, is highly complex and subject to interpretation. The presentation of our financial condition and results of operations is based upon our current interpretation of the provisions contained in the Tax Cuts and Jobs Act. In the future, the Treasury Department and the Internal Revenue Service are expected to release regulations relating to and interpretive guidance of the legislation contained in the Tax Cuts and Jobs Act. Any significant variance of our current interpretation of such legislation from any future regulations or interpretive guidance could result in a change to the presentation of our financial condition and results of operations and could negatively affect our business.

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.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases. These efforts have included consideration of cap-and-trade programs, carbon taxes, greenhouse gas reporting and tracking programs, and regulations that directly limit greenhouse gas emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented. The EPA, however, has adopted regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act (the “CAA”). The EPA adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources through preconstruction and operating permit requirements.

The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, on an annual basis. Recent regulation of emissions of

 

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greenhouse gases has focused on fugitive methane emissions. For example, in June 2016, the EPA finalized rules that established new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission, and storage activities. However, in June 2017, the EPA published a proposed rule to stay certain portions of the 2016 rule for two years and to reconsider the entirety of the 2016 rule, but the agency has not yet published a final rule and, as a result, the 2016 rule is currently in effect but future implementation of the 2016 rule is uncertain. Compliance with these rules if fully or partially implemented could result in increased compliance costs on our operations.

In addition, while the United States Congress has not taken any legislative action to reduce emissions of greenhouse gases, many states have established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

Additionally, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own greenhouse gas emissions targets and be transparent about the measures each country uses to achieve its greenhouse gas emissions targets. The Paris Agreement entered into force on November 4, 2016. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

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 to comply with new regulatory or reporting requirements. Substantial limitations on greenhouse gas emissions could also adversely affect demand for the oil and natural gas we produce and lowers the value of our reserves. 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. Additionally, with concerns over GHG emissions, certain non-governmental activists have recently directed their efforts at advocating the shifting of funding away from companies with energy-related assets, which could result in limitations or restrictions on certain sources of funding for the energy sector.

In addition, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damage, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Finally, 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, floods, and other climatic events. Our offshore operations are particularly at risk from severe climatic events. If any such climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

 

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The enactment of derivatives legislation 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.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), enacted on July 21, 2010, expanded federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Act requires the U.S. Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC and the SEC have finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this is accomplished.

In one of its rulemaking proceedings still pending under the Act, the CFTC issued on December 5, 2016, re-proposed rules imposing position limits for certain futures and option contracts in various commodities (including oil and gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also requires us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or to take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps to be entered into to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, certain banking regulators and the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for, and to utilize, the end-user exception from such margin requirements for swaps to be entered into to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows.

The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are fully implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we may encounter, or reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

In addition, the European Union and other non-U.S. jurisdictions have implemented and continue to implement new regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become directly subject to such regulations and in any event the global derivatives market are affected to the extent that foreign counterparties are affected by such regulations. At this time, the impact of such regulations is not clear.

 

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Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our oil, natural gas, and natural gas liquids, we periodically enter into oil, natural gas, and natural gas liquids price hedging arrangements with respect to a portion of our expected production. Our hedging policy is expected to provide that we enter into hedging arrangements covering up to the following maximum percentages of volumes: (i) 90% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed producing volumes during months January through July and November through December, (ii) 65% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed producing volumes during months August through October, (iii) 50% of the reasonably anticipated quarterly production of oil, natural gas, and natural gas liquids of proved developed non-producing volumes during months January through July and November through December and (iv) 0% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids of its proved developed non-producing volumes during months August through October. These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

 

   

our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;

 

   

there is a widening of price differentials between delivery points for our production and the delivery point to be assumed in the hedge arrangement;

 

   

the counterparties to our futures contracts fails to perform the contracts;

 

   

a sudden, unexpected event materially impacts oil or natural gas prices; or

 

   

we are unable to market our production in a manner contemplated when entering into the hedge contract.

All of our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

Risks Related to Our Indebtedness and the Notes

Our substantial indebtedness could materially and adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under the Notes.

After the Stone Combination, we are a highly leveraged company. As of June 30, 2018, we had approximately $647.7 million face value of outstanding indebtedness (in addition to approximately $354.0 million of undrawn commitments under the Bank Credit Facility, taking into account approximately $6.0 million of letters of credit). For the remainder of 2018, we have total debt service payment obligations of approximately $29.2 million.

Our substantial indebtedness could have important consequences for you as a holder of the Notes. For example, it could:

 

   

limit our ability to borrow money for our working capital, capital expenditures, debt service requirements, strategic initiatives or other purposes;

 

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make it more difficult for us to satisfy our obligations with respect to our indebtedness, including the Notes, and any failure to comply with the obligations of any of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the indenture governing the Notes and the agreements governing our other indebtedness;

 

   

require us to dedicate a substantial portion of our cash flow from operations to the repayment of our indebtedness, thereby reducing funds available to us for other purposes;

 

   

limit our flexibility in planning for, or reacting to, changes in our operations or business;

 

   

make us more highly leveraged than some of our competitors, which may place us at a competitive disadvantage;

 

   

make us more vulnerable to downturns in our business or the economy;

 

   

restrict us from making strategic acquisitions, engaging in development activities, introducing new technologies or exploiting business opportunities;

 

   

cause us to make non-strategic divestitures;

 

   

limit, along with the financial and other restrictive covenants in the agreements governing our indebtedness, among other things, our ability to borrow additional funds or dispose of assets;

 

   

prevent us from raising the funds necessary to repurchase all Notes tendered to us upon the occurrence of certain changes of control, which failure to repurchase would constitute a default under the indenture governing the Notes; or

 

   

expose us to the risk of increased interest rates, as certain of our borrowings, including borrowings under the Bank Credit Facility, are at variable rates of interest.

In addition, the Bank Credit Facility contains, and the indenture governing the Notes contains, restrictive covenants that limit our ability to engage in activities that may be in our long-term best interest. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of substantially all of our indebtedness.

Despite our substantial indebtedness, we may still be able to incur significantly more debt, including secured debt, which could intensify the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial indebtedness in the future. Although the terms of the Bank Credit Facility contains, and the indenture governing the Notes contains, restrictions on our and our subsidiaries’ ability to incur additional indebtedness, including first-priority secured indebtedness that will be effectively senior to the Notes, these restrictions are subject to a number of important qualifications and exceptions, and the indebtedness incurred in compliance with these restrictions could be substantial. These restrictions also will not prevent us from incurring obligations that do not constitute indebtedness. As of June 30, 2018, we had approximately $354.0 million available for additional borrowing under the Bank Credit Facility (taking into account approximately $6.0 million of letters of credit), all of which would be secured on a first-priority basis senior to the Notes to the extent of the value of the collateral securing the Bank Credit Facility. In addition to the Notes and our borrowings under the Bank Credit Facility, the covenants under any other existing or future debt instruments could allow us to incur a significant amount of additional indebtedness and, subject to certain limitations, such additional indebtedness could be secured senior to the Notes or on a pari passu basis with the Notes. The more leveraged we become, the more we, and in turn our security holders, will be exposed to certain risks described above under “—Our substantial indebtedness could materially and adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under the Notes.”

 

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We may not be able to generate sufficient cash to service all of our indebtedness, including the Notes, and to fund our working capital and capital expenditures, and may be forced to take other actions to satisfy our obligations under our indebtedness that may not be successful.

Our ability to pay principal and interest on the Notes and to satisfy our other debt obligations will depend upon, among other things:

 

   

our future financial and operating performance (including the realization of any estimated cost-savings described herein), which will be affected by prevailing economic, industry and competitive conditions and financial, business, legislative, regulatory and other factors, many of which are beyond our control; and

 

   

our future ability to borrow under the Bank Credit Facility, the availability of which depends on, among other things, our complying with the covenants in the credit agreement governing such facility.

We cannot assure you that our business will generate cash flow from operations, or that we will be able to draw under the Bank Credit Facility or otherwise, in an amount sufficient to fund our liquidity needs, including the payment of principal and interest on the Notes.

If our cash flows and capital resources are insufficient to service our indebtedness, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the Notes. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. We cannot assure you that we will be able to restructure or refinance any of our debt on commercially reasonable terms or at all. In addition, the terms of existing or future debt agreements, including the credit agreement governing the Bank Credit Facility and the indenture governing the Notes, may restrict us from adopting some of these alternatives. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate those dispositions for fair market value or at all. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations then due. Our inability to generate sufficient cash flow to satisfy our debt obligations, or to refinance our indebtedness on commercially reasonable terms or at all, could result in a material adverse effect on our business, results of operations and financial condition and could negatively impact our ability to satisfy our obligations under the Notes.

If we cannot make scheduled payments on our indebtedness, we will be in default and holders of the Notes could declare all outstanding principal and interest to be due and payable, the lenders under the Bank Credit Facility could terminate their commitments to loan money, our secured lenders (including the lenders under the Bank Credit Facility and the holders of the Notes) could foreclose against the assets securing the indebtedness owing to them (and the proceeds of any such foreclosure may not be sufficient to satisfy their claims), and we could be forced into bankruptcy or liquidation. All of these events could cause you to lose all or part of your investment in the Notes.

If our indebtedness is accelerated, we may need to repay or refinance all or a portion of our indebtedness, including the Notes, before maturity. There can be no assurance that we will be able to obtain sufficient funds to enable us to repay or refinance our debt obligations, including the Bank Credit Facility, on commercially reasonable terms, or at all.

Repayment of our debt, including the Notes, is dependent on cash flow generated by our subsidiaries.

We are a holding company and have no direct operations other than holding the equity interests in our subsidiaries and activities directly related thereto. Accordingly, repayment of our indebtedness, including the

 

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Notes, is dependent on the generation of cash flow by our subsidiaries and (if they are not guarantors of the Notes) their ability to make such cash available to us, by dividend, debt repayment or otherwise. Unless they are guarantors of the Notes, our subsidiaries do not have any obligation to pay amounts due on the Notes or to make funds available for that purpose. Our subsidiaries may not be able to, or may not be permitted to, make distributions to enable us to make payments in respect of our indebtedness, including the Notes. Each of our subsidiaries is a distinct legal entity, and under certain circumstances legal and contractual restrictions may limit our ability to obtain cash from them and we may be limited in our ability to cause any future joint ventures to distribute their earnings to us. While the Bank Credit Facility limits, and the indenture governing the Notes will limit, the ability of our subsidiaries to incur consensual restrictions on their ability to pay dividends or make other intercompany payments to us, these limitations are subject to certain qualifications and exceptions. In the event that we do not receive distributions from our non-guarantor subsidiaries, we may be unable to make required principal and interest payments on our indebtedness, including the Notes.

If we default on our obligations to pay our other indebtedness, we may not be able to make payments on the Notes.

Any default under the agreements governing our indebtedness, including defaults under the Bank Credit Facility that are not waived by the required lenders, and the remedies sought by the holders of such indebtedness could leave us unable to pay principal, premium, if any, or interest on the Notes and could substantially decrease the market value of the Notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness (including the Bank Credit Facility), we could be in default under the terms of the agreements governing such indebtedness. Upon an event of default, the holders of such indebtedness could elect to (i) declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, (ii) terminate their commitments and cease making further loans and (iii) institute foreclosure proceedings against our assets (and the proceeds of any such foreclosure may not be sufficient to satisfy their claims), and we could be forced into bankruptcy or liquidation. Upon any event of default, all payments will be made to repay the Bank Credit Facility before the Notes are repaid.

If our operating performance declines, we may in the future need to seek waivers or forbearance from the required lenders under the Bank Credit Facility to avoid being in default. If we breach our covenants under the Bank Credit Facility and seek a waiver, we may not be able to obtain a waiver and/or forbearance from the required lenders. If this occurs, we would be in default under the Bank Credit Facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. See “Description of Other Indebtedness” and “Description of the Notes.”

Upon any such bankruptcy filing under Title 11 of the United States Code, as amended (the “Bankruptcy Code”) or under any applicable similar law of any other jurisdiction, we would be stayed from making any ongoing payments on the Notes, and the holders of the Notes would not be entitled to receive post-petition interest or applicable fees, expenses, costs or charges to the extent the amount of the obligations due under the Notes exceeded the value of the collateral (after taking into account all other first-priority or second-priority secured debt that was also secured by the collateral), or any “adequate protection” on account of any undersecured portion of the Notes.

The Notes will be structurally subordinated to all liabilities of our current and future non-guarantor subsidiaries.

The Notes will be structurally subordinated to indebtedness and other liabilities of our current and future subsidiaries that are not or will not be guaranteeing the Notes, and the claims of creditors of these subsidiaries, including trade creditors, will have priority as to the assets of these subsidiaries. In the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay

 

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the holders of their debts (secured and unsecured), holders of preferred equity interests and their trade creditors before they will be able to distribute the value of any of their assets to us.

In addition, the indenture governing the Notes will, subject to some limitations, permit these non-guarantor subsidiaries to incur additional indebtedness and will not contain any limitation on the amount of other liabilities, such as trade payables, that may be incurred by these subsidiaries.

The Notes will not be guaranteed by any of our non-U.S. subsidiaries or certain other excluded subsidiaries. These non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the Notes, or to make any funds available therefore, whether by dividends, loans, distributions or other payments. Any right that we or the subsidiary guarantors have to receive any assets of any non-guarantor subsidiaries upon the insolvency, liquidation or reorganization of those subsidiaries, and the consequent rights of holders of Notes to realize proceeds from the sale of any of those subsidiaries’ assets, will be effectively subordinated to the claims of those subsidiaries’ creditors, including trade creditors and holders of preferred equity interests of those subsidiaries.

Our debt agreements contain restrictions that will limit our flexibility in operating our business.

The Bank Credit Facility and the indenture governing the Notes contain, and any other existing or future indebtedness of ours would likely contain, a number of covenants that will impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries ability to, among other things:

 

   

incur additional debt, guarantee indebtedness or issue certain preferred equity interests;

 

   

pay dividends on or make distributions in respect of, or repurchase or redeem, our equity interests or make other restricted payments;

 

   

prepay, redeem or repurchase certain debt;

 

   

make loans or certain investments;

 

   

sell certain assets;

 

   

create liens on certain assets;

 

   

consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;

 

   

enter into certain transactions with our affiliates;

 

   

alter the businesses we conduct;

 

   

enter into agreements restricting our subsidiaries’ ability to pay dividends; and

 

   

designate our subsidiaries as unrestricted subsidiaries.

In addition, the Bank Credit Facility requires us in certain circumstances to comply with a financial covenant. See “Description of Other Indebtedness.”

As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

A failure to comply with the covenants under the Bank Credit Facility or any of our other future indebtedness could result in an event of default, which, if not cured or waived, could have a material adverse effect on our business, financial condition and results of operations. In the event of any such default, the lenders thereunder:

 

   

will not be required to lend any additional amounts to us;

 

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could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be immediately due and payable and terminate all commitments to extend further credit;

 

   

could require us to apply all of our available cash to repay these borrowings; or

 

   

could effectively prevent us from making debt service payments on the Notes;

any of which could result in an event of default under the Notes.

Such actions by the lenders could cause cross defaults under our other indebtedness. If we were unable to repay those amounts, the lenders under the Bank Credit Facility could proceed against the collateral granted to them to secure that indebtedness. We have pledged a significant portion of our assets as collateral under the Bank Credit Facility.

If any of our outstanding indebtedness under the Bank Credit Facility or our other indebtedness, including the Notes, were to be accelerated, there can be no assurance that our assets would be sufficient to repay such indebtedness in full. See “Description of Other Indebtedness” and “Description of the Notes.”

We may not be able to repurchase the Notes upon a change of control.

Upon the occurrence of certain specific kinds of change of control events, we will be required to offer to repurchase all of the outstanding Notes at 101% of the principal amount thereof plus, without duplication, accrued and unpaid interest, if any, to the date of repurchase. Additionally, under the Bank Credit Facility, a change of control constitutes an event of default that permits the lenders to accelerate the maturity of borrowings and terminate their commitments to lend. The source of funds for any repurchase of the Notes and repayment of borrowings under the Bank Credit Facility would be our available cash or cash generated from our subsidiaries’ operations or other sources, including borrowings, sales of assets or sales of equity. It is possible that we will not have sufficient funds at the time of a change of control to make the required repurchase of Notes or that restrictions in the Bank Credit Facility will not allow such repurchases. We may require additional financing from third parties to fund any such repurchases, and we may be unable to obtain financing on satisfactory terms or at all. Further, our ability to repurchase the Notes may be limited by law. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a change of control under the indenture governing the Notes. See “Description of the Notes—Change of Control.”

Courts interpreting change of control provisions under New York law (which will be the governing law of the indenture governing the Notes) have not provided clear and consistent meanings of such change of control provisions, which leads to subjective judicial interpretation. In addition, a court case in Delaware has questioned whether a change of control provision contained in an indenture could be unenforceable on public policy grounds.

We may enter into transactions that would not constitute a change of control that could affect our ability to satisfy our obligations under the Notes.

Legal uncertainty regarding what constitutes a change of control and the provisions of the indenture governing the Notes may allow us to enter into transactions, such as acquisitions, refinancings or recapitalizations, that would not constitute a change of control but may increase our outstanding indebtedness or otherwise affect our ability to satisfy our obligations under the Notes. The definition of change of control for purposes of the Notes includes a phrase relating to the transfer of “all or substantially all” of our assets taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, your ability to require us to repurchase Notes as a result of a transfer of less than all of our assets to another person may be uncertain.

 

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Federal and state statutes allow courts, under specific circumstances, to void the Notes and guarantees and the related security interests and require holders of Notes to return payments received.

If we or any subsidiary guarantor becomes a debtor in a case under the Bankruptcy Code or any applicable law of any other jurisdiction or encounters other financial difficulty, under federal or state fraudulent transfer or fraudulent conveyance law, a court may void or otherwise decline to enforce the Notes or the guarantees and the related security interests. A court might do so if it found that when we issued the Notes or the subsidiary guarantor entered into its guarantee and granted the related security interests, or in some states when payments became due under the Notes or the guarantees, we or the subsidiary guarantor received less than reasonably equivalent value or fair consideration and:

 

   

was insolvent or rendered insolvent by reason of such incurrence;

 

   

was left with inadequate capital to conduct its business;

 

   

believed or reasonably should have believed that it would incur debts beyond its ability to pay; or

 

   

was a defendant in an action for money damages or had a judgment for money damages docketed against us or the subsidiary guarantor if, in either case, the judgment is unsatisfied after final judgment.

The court might also void an issuance of Notes or a guarantee or the related security interest, without regard to the above factors, if the court found that we issued the Notes or the applicable subsidiary guarantor entered into its guarantee and provided the related security interest with actual intent to hinder, delay or defraud its creditors.

As a general matter, value is given for a transfer or an obligation if, in exchange for the transfer or obligation, property is transferred or a valid antecedent debt is satisfied. A court would likely find that the Issuers or a subsidiary guarantor did not receive reasonably equivalent value or fair consideration for the Notes or its guarantee or the related security interest if the Issuers or such subsidiary guarantor did not substantially benefit directly or indirectly from the issuance of the Notes. Thus, if the guarantees were legally challenged, any guarantee could be subject to the claim that, since the guarantee was incurred for our benefit, and only indirectly for the benefit of the subsidiary guarantor, the obligations of the applicable subsidiary guarantor were incurred for less than reasonably equivalent value or fair consideration.

The measures of insolvency for purposes of these fraudulent transfer or fraudulent conveyance laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer or fraudulent conveyance has occurred. Generally, however, the Issuers or a subsidiary guarantor would be considered insolvent if:

 

   

the sum of its debts, including contingent liabilities, was greater than the fair value of all of its assets;

 

   

if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as they become absolute and mature;

 

   

it engaged, or was about to engage, in business or a transaction, with unreasonably small capital; or

 

   

it could not pay its debts as they become due.

We cannot assure you as to what standard a court would apply in determining whether the Issuers or the subsidiary guarantors were solvent at the relevant time or that a court would agree with our conclusions in this regard, or, regardless of the standard that a court uses, that it would not determine that the Issuers or a subsidiary guarantor were indeed insolvent on that date; that this exchange or any payments to the holders of the Notes (including under the guarantees) did not constitute preferences, fraudulent transfers or fraudulent conveyances on other grounds; or that the issuance of the Notes and the guarantees would not be declared subordinated to the Issuers’ or any subsidiary guarantor’s other debt, including by way of equitable subordination.

 

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Although each guarantee entered into by a subsidiary guarantor will contain a provision intended to limit that subsidiary guarantor’s liability to the maximum amount that it could incur without causing the incurrence of obligations under its guarantee to be a fraudulent transfer or fraudulent conveyance or otherwise avoidable, this provision may not be effective as a legal matter to protect those guarantees from being voided under fraudulent transfer or fraudulent conveyance or other applicable law, or may reduce that guarantor’s obligation to an amount that effectively makes its guarantee worthless.

If a court were to void the issuance of the Notes or any guarantee or the related security interest, you would no longer have any claim against the Issuers or the applicable subsidiary guarantor, or the right to enforce or otherwise benefit from the applicable collateral. Sufficient funds to repay the Notes may not be available from other sources, including the remaining obligors, if any. In addition, the court might direct you to repay any amounts that you already received from the Issuers or a subsidiary guarantor. In the event of a finding that a fraudulent transfer or fraudulent conveyance occurred, you may not receive any repayment on the Notes. Further, the avoidance of the Notes could result in an event of default with respect to our and our subsidiaries’ other debt, which could result in acceleration of that debt.

In addition, any payment by the Issuers pursuant to the Notes or by a subsidiary guarantor under a guarantee made at a time the Issuers or such subsidiary guarantor were found to be insolvent could be voided and required to be returned to the Issuers or such subsidiary guarantor or to a fund for the benefit of the Issuers’ or such subsidiary guarantor’s creditors if such payment is made to an insider within a one-year period prior to a bankruptcy filing or within 90 days for any non-insider party and such payment would give the recipient thereof more than such party would have received in a distribution under Chapter 7 of the Bankruptcy Code in a hypothetical Chapter 7 case.

Finally, as a court of equity, the bankruptcy court may subordinate the claims in respect of the Notes or guarantees to other claims against us under the principle of equitable subordination if the court determines that (a) the holder of Notes engaged in some type of inequitable conduct, (b) the inequitable conduct resulted in injury to our other creditors or conferred an unfair advantage upon the holders of Notes and (c) equitable subordination is not inconsistent with the provisions of the Bankruptcy Code.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under the Bank Credit Facility are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on certain of our variable rate indebtedness will increase even though the amount borrowed remained the same, and our net income and cash flows, including cash available for servicing our indebtedness, will correspondingly decrease. Assuming the Bank Credit Facility was fully drawn at $600.0 million on June 30, 2018, each 0.125% change in assumed blended interest rates would result in a $0.8 million change in annual interest expense on indebtedness under the Bank Credit Facility. In the future, we may enter into interest rate swaps that involve the exchange of floating for fixed rate interest payments in order to reduce interest rate volatility. However, we may not maintain interest rate swaps with respect to all of our variable rate indebtedness, and any swaps we enter into may not fully mitigate our interest rate risk, may prove disadvantageous or may create additional risks.

Your ability to transfer the Notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market will develop, or if developed be maintained, for the Notes.

The Notes are a new issue of securities for which there is no established trading market. We do not intend to have the Notes listed on a national securities exchange or included in any automated quotation system. Therefore, an active market for any of the Notes may not develop or, if developed, it may not continue. The liquidity of any market for the Notes will depend upon the number of holders of the Notes, our performance, the market for similar securities, the interest of securities dealers in making a market in the Notes and other factors. A liquid

 

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trading market may not develop for the Notes. If an active market does not develop or is not maintained, the price and liquidity of the Notes may be materially and adversely affected. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the Notes. The market, if any, for any of the Notes may not be free from similar disruptions and any such disruptions may materially and adversely affect the prices at which you may sell your Notes. In addition, the Notes may trade at a discount from their value on the date you acquired the Notes, depending upon prevailing interest rates, the market for similar notes, our performance and other factors.

We may be unable to repay or repurchase the Notes at maturity.

At maturity, the entire outstanding principal amount of the Notes, together with accrued and unpaid interest, if any, will become due and payable. We may not have the funds to fulfill these obligations or the ability to renegotiate these obligations. If, upon the maturity date, other arrangements prohibit us from repaying the Notes, we could try to obtain waivers of such prohibitions from the lenders and holders under those arrangements, or we could attempt to refinance the borrowings that contain the restrictions. In these circumstances, if we were not able to obtain such waivers or refinance these borrowings, we would be unable to repay the Notes.

The market price for the Notes may be volatile and may require you to hold the Notes until maturity.

Historically, the market for non-investment grade debt, such as the Notes, has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the Notes. Any market that may develop for the Notes may be subject to similar disruptions. In addition, subsequent to their initial issuance, the Notes may trade at a discount from their initial offering price, depending upon prevailing interest rates, the market for similar notes, our performance and other factors. As a result, you may be required to hold the Notes until maturity unless you are willing to sell the Notes for a loss.

Many of the restrictive covenants contained in the indenture governing the Notes will not apply during any period in which the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and the holders of the Notes will lose the protection of these covenants during any such periods.

Many of the covenants contained in the indenture governing the Notes will not apply to us during any period in which the Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Group, provided that at the time such ratings are obtained no default or event of default has occurred and is continuing. Such covenants will include restrictions on, among other things, our ability to make certain distributions, incur indebtedness and enter into certain other transactions. There can be no assurance that the Notes will ever be rated investment grade or that if the Notes ever are rated investment grade they will maintain these ratings. However, suspension of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force. For example, during any such suspension of these covenants, we would be able to make dividends and distributions and incur substantial additional debt in amounts that would not otherwise be permitted while these covenants were in force. To the extent the covenants are subsequently reinstated, any such actions taken while the covenants were suspended would not result in an event of default under the indenture governing the Notes. See “Description of the Notes—Certain Covenants.”

If the Internal Revenue Service (“IRS”) makes audit adjustments to Holdings’ income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from Holdings, in which case Holdings’ ability to service the Notes and Holdings’ other debt obligations could be negatively impacted.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to Holdings’ income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from Holdings. If,

 

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as a result of any such audit adjustments, Holdings is required to make payments of taxes, penalties and interest, Holdings’ cash available for servicing the Notes and Holdings’ other debt obligations might be substantially reduced.

Risks Related to the Collateral

The Notes and guarantees are subject to the Senior Lien Intercreditor Agreement that provides the Notes and the guarantees are effectively subordinated to the Bank Credit Facility and other creditors who have a first-priority security interest in our assets to the extent of the value of such assets.

Substantially all the assets owned by the Issuers and the subsidiary guarantors or thereafter acquired, and all proceeds therefrom, are subject to first-priority liens in favor of the lenders and other secured parties under the Bank Credit Facility. The collateral agent for the Notes (the “Notes Collateral Agent”) is a party to the Senior Lien Intercreditor Agreement which provides that, at any time that any obligations that are secured by first-priority liens remain outstanding, any actions that may be taken in respect of the collateral (including the ability to commence enforcement proceedings against the collateral and to control the conduct of such proceedings) will be at the direction of the holders of such indebtedness, subject to the rights of the Notes Collateral Agent after the expiration of a 180-day standstill period if the secured parties under the Bank Credit Facility are not exercising remedies (or stayed from exercising remedies) at such time. Under such circumstances, the trustee and the Notes Collateral Agent on behalf of the holders of Notes and all holders of indebtedness that are deemed to rank equally with the Notes will not have the ability to control or direct such actions, even if the rights of the holders of Notes are materially and adversely affected subject to the rights of the Notes Collateral Agent after such standstill period. Further, in the event that the Issuers or a subsidiary guarantor files for or is declared bankrupt, becomes insolvent or is liquidated or reorganized, its obligations under the Bank Credit Facility will be entitled to be paid in full from its assets pledged as security for such obligations before any payment from such assets or the proceeds thereof may be made with respect to the Notes. Holders of the Notes would then participate ratably in the remaining assets pledged as collateral, with all holders of indebtedness that are deemed to rank equally with the Notes based upon the respective amount owed to each creditor. Also, under the Senior Lien Intercreditor Agreement, the holders of the Notes may be required to turn over certain funds they may receive in any bankruptcy or liquidation proceeding to the lenders under the Bank Credit Facility under certain circumstances.

In addition, if the Issuers and/or any subsidiary guarantor defaults under the Bank Credit Facility, the lenders and other secured parties holding first-priority obligations could declare all of the funds borrowed thereunder, together with accrued and unpaid interest, immediately due and payable and foreclose on the pledged assets. However, if there were an event of default under the Notes, the holders of obligations that are secured by first-priority liens could decide not to proceed against the collateral, regardless of whether or not there is a default under such obligations that are secured by first-priority liens.

Furthermore, if the lenders and other secured parties under the Bank Credit Facility foreclose and sell the pledged equity interests in any subsidiary guarantor, then that subsidiary guarantor will be released from its guarantee of the Notes automatically and immediately upon such sale. By virtue of the direction of the administration of the pledges and security interests and the release of collateral, actions may be taken under the collateral documents that may be adverse to holders of the Notes.

The liens on the collateral are subordinated in the manner set forth in the Senior Lien Intercreditor Agreement to all senior liens thereon governed by the Senior Lien Intercreditor Agreement (including the liens granted to the lenders under the Bank Credit Facility and other creditors that may have the benefit of first-priority liens on such collateral from time to time, whether on or after the date the Notes and related guarantees are issued), irrespective of the time, order or method of creation, attachment or perfection of any such junior or senior liens or any failure, defect or deficiency or alleged failure, defect or deficiency in any of the foregoing. Accordingly, the liens of the holders of the Notes on the collateral will be subject to any and all exceptions, defects, encumbrances, liens and other imperfections as may be accepted by our creditors with prior liens

 

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thereon. The existence of any such exceptions, defects, encumbrances, liens and other imperfections could adversely affect the value of the collateral as well as the ability of the Notes Collateral Agent to realize or foreclose on such collateral.

In addition, the Senior Lien Intercreditor Agreement provides that if the holders of the Notes obtain possession of any collateral or realize any proceeds or payment in respect of any such collateral pursuant to their security documents or by the exercise of any rights available to them under applicable law or in any bankruptcy or liquidation proceeding or through any other exercise of remedies, at any time prior to the associated discharge of the obligations under the Bank Credit Facility and any other first-priority obligations secured, or intended to be secured, by such collateral, then such holders will be obligated to hold such collateral, proceeds or payment in trust for the lenders under the Bank Credit Facility and the holders of any other first-priority obligations and transfer such collateral, proceeds or payment, as the case may be, to the representative thereof. Thus, there can be no assurances that under the Senior Lien Intercreditor Agreement the holders of the Notes would not be obligated to turn over to the lenders under the Bank Credit Facility and the holders of any other first-priority obligations certain funds they may receive in respect of the collateral (including funds they may receive from such collateral pursuant to a plan of reorganization in a bankruptcy proceeding).

Under the Senior Lien Intercreditor Agreement, the authorized representative of the holders of the Notes may not object following the filing of a bankruptcy petition to any debtor-in-possession financing or to the use of the collateral to secure that financing that has been consented to by the lenders under the Bank Credit Facility, subject to certain conditions and limited exceptions, and is also restricted in taking various other actions or objecting to certain other matters in any insolvency or liquidation proceeding of Holdings or a subsidiary guarantor. See “Description of the Notes—Security Documents—Senior Lien Intercreditor Agreement.” After such a filing, the value of such collateral could materially deteriorate, and the holders of the Notes would be unable to raise an objection.

Because each subsidiary guarantor’s liability under its guarantee may be reduced to zero, avoided or released under certain circumstances, you may not receive any payments from some or all of the subsidiary guarantors.

The guarantee by each subsidiary guarantor is limited to the maximum amount that such subsidiary guarantor is permitted to guarantee under applicable law. As a result, any such subsidiary guarantor’s liability under its guarantee could be reduced to zero, depending on the amount of other obligations of such subsidiary guarantor. Further, under the circumstances discussed more fully below, a court under federal or state fraudulent conveyance and transfer statutes could void the obligations under a guarantee or any related security interests or further subordinate it to all other obligations of the subsidiary guarantor. See “—Federal and state statutes allow courts, under specific circumstances, to void the Notes and guarantees and the related security interests, and require holders of Notes to return payments received.”

In addition, the subsidiary guarantors will be automatically released from their guarantees upon the occurrence of certain events, including the following:

 

   

the designation of a subsidiary guarantor as an unrestricted subsidiary pursuant to the indenture governing the Notes;

 

   

such subsidiary ceasing to be a subsidiary as a result of any foreclosure of any pledge or security interest in favor of the Bank Credit Facility or other exercise of remedies in respect thereof; or

 

   

the release or discharge of any guarantee or indebtedness that resulted in the creation of the guarantee of the Notes by a subsidiary guarantor subject to the terms of the indenture governing the Notes; or

 

   

the sale or other disposition of the capital stock of a subsidiary guarantor in a transaction not prohibited under the indenture governing the Notes.

If the guarantee of any subsidiary guarantor is released, no holder of the Notes will have a claim as a creditor against that subsidiary, and the indebtedness and other liabilities, including trade payables and preferred

 

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equity interests, if any, whether secured or unsecured, of that subsidiary will be structurally senior to the claim of any holders of the Notes. See “Description of the Notes—Subsidiary Guarantees.”

It may be difficult to realize the value of the collateral securing the Notes.

The collateral securing the Notes is subject to any and all exceptions, defects, encumbrances, liens and other imperfections. The existence of any such exceptions, defects, encumbrances, liens and other imperfections could materially and adversely affect the value of the collateral securing the Notes as well as the ability of the Notes Collateral Agent to realize or foreclose on such collateral.

The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers. By their nature, some or all of the pledged assets may be illiquid and may have no readily ascertainable market value. We cannot assure you that the fair market value of the collateral as of the date of this prospectus equals or exceeds the principal amount of the debt secured thereby. The value of the assets pledged as collateral for the Notes could be impaired in the future as a result of changing economic conditions, our failure to implement our business strategy, competition, unforeseen liabilities and other future events. Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the Notes. After the payment of all first lien obligations, any claim for the difference between the amount, if any, realized by holders of the Notes from the sale of the collateral securing the Notes and the obligations under the Notes and other obligations secured on a pari passu basis with the Notes will rank equally in right of payment with all of our other unsecured unsubordinated indebtedness and other obligations, including trade payables. Additionally, in the event that a bankruptcy case or similar proceeding is commenced by or against us, if the value of the collateral is less than the amount of principal and accrued and unpaid interest on the Notes and all other senior secured second-priority obligations, interest, fees and expenses may cease to accrue on the Notes from and after the date such case or proceeding is commenced. See “—If we become the subject of a bankruptcy proceeding, bankruptcy laws may limit your ability to realize value from the collateral.”

The security interest of the Notes Collateral Agent is subject to practical problems generally associated with the realization of security interests in collateral. For example, the Notes Collateral Agent may need to obtain the consent of a third party to obtain or enforce a security interest in a contract. We cannot assure you that the Notes Collateral Agent will be able to obtain any such consent. We also cannot assure you that the consents of any third parties will be given when required to facilitate a foreclosure on such assets. Accordingly, the Notes Collateral Agent may not have the ability to foreclose upon those assets and the value of the collateral may significantly decrease.

In addition, the collateral securing the Notes is subject to liens permitted under the terms of the indenture governing the Notes, whether arising on or after the date the Notes are issued, such as purchase money indebtedness and capital lease obligations, and assets subject to such liens will in certain circumstances be excluded from the collateral. Such liens may be senior to or pari passu with the lien of the holders of the Notes. The existence of any permitted liens could materially and adversely affect the value of the collateral securing the Notes, as well as the ability of the Notes Collateral Agent to realize or foreclose on such collateral.

Furthermore, not all of the Issuers’ and subsidiary guarantors’ assets will secure the Notes. See “Description of the Notes—Security.” For example, the collateral will not include, among other things:

 

   

certain real property;

 

   

certain motor vehicles and certain commercial tort claims;

 

   

those assets over which the pledging or granting of security interests in such assets would be prohibited by applicable law, rule, regulation or certain contractual obligations (in each case, except to the extent such prohibition is unenforceable after giving effect to applicable anti-assignment provisions of Article 9 of the Uniform Commercial Code);

 

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assets to the extent that such security interests would require obtaining the consent of any governmental authority (to the extent not obtained) or would result in materially adverse tax consequences as reasonably determined by Holdings in writing delivered to the Notes Collateral Agent; or

 

   

certain other assets.

Some of these assets may be material to us and such exclusion could have a material adverse effect on the value of the collateral.

To the extent that the claims of the holders of the Notes exceed the value of the assets securing the Notes and other liabilities, those claims will rank equally with the claims of the holders of any of our unsecured unsubordinated indebtedness. As a result, if the value of the assets pledged as security for the Notes and other liabilities is less than the value of the claims of the holders of the Notes and other secured liabilities, those claims may not be satisfied in full before the claims of our unsecured creditors are also satisfied in full or in part.

Rights in the collateral may be materially and adversely affected by the failure to perfect security interests in collateral now or in the future.

The collateral includes substantially all of the Issuers’ and the subsidiary guarantors’ tangible and intangible assets that secure indebtedness under the Bank Credit Facility, whether now owned or acquired or arising in the future, subject to certain exceptions. Applicable law provides that a security interest in certain tangible and intangible assets can only be properly perfected and its priority retained through certain actions undertaken by the secured party. We will be required to file or cause to be filed financing statements under the Uniform Commercial Code to perfect the security interests that can be perfected by such filings. We and the subsidiary guarantors have limited obligations to perfect the security interest of the holders of the Notes in specified collateral other than the filing of financing statements, delivery of certain stock certificates and instruments, if permitted by the Senior Lien Intercreditor Agreement, and filings with the United States Patent and Trademark Office and the United States Copyright Office, as applicable, and the filing of mortgages and other perfection actions required by the security documents. Any issues that we are not able to resolve in connection with the delivery and recordation of such security interests may negatively impact the value of the collateral. See “—If we become the subject of a bankruptcy proceeding, bankruptcy laws may limit your ability to realize value from the collateral” below.

The indenture governing the Notes and the security documents entered into in connection with the Notes do not require us to take a number of actions that might improve the perfection or priority of the liens of the Notes Collateral Agent for the benefit of the noteholders. As a result of these limitations, the security interest of the Notes Collateral Agent for the benefit of the noteholders in a portion of the collateral may not be perfected or enforceable (or may be subject to other liens) under applicable law.

The security interests of the note holders in after-acquired assets may not be perfected in a timely manner or at all.

If additional domestic restricted subsidiaries are formed or acquired and become subsidiary guarantors under the indenture governing the Notes, additional financing statements would be required to be filed to perfect the security interest in the assets of such subsidiary guarantors. Depending on the type of the assets constituting after-acquired collateral, additional action may be required to be taken to perfect the security interest in such assets, such as the delivery of physical collateral, if permitted by the Senior Lien Intercreditor Agreement, or the execution and recordation of mortgages or deeds of trust. Applicable law provides that certain property and rights acquired after the grant of a general security interest, such as real property, certain intellectual property and certain proceeds, can only be perfected at the time such property and rights are acquired and identified. The Notes Collateral Agent will not monitor and has no obligation to monitor, and there can be no assurance that we

 

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will inform the Notes Collateral Agent of, the future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. Such failure may result in the loss of the security interest in the collateral or the priority of the security interest in favor of the Notes Collateral Agent, as applicable, against third parties. Even if the Notes Collateral Agent does take all actions necessary to create properly perfected security interests on collateral acquired in the future, any such security interests that are perfected after the date of the indenture would (as described further herein) remain at risk of being avoided under certain circumstances as a preferential transfer or otherwise in any bankruptcy case or similar proceeding even after the security interests perfected on the closing date were no longer subject to such risk. See “—Delivery of security interests in collateral or any guarantees after the issue date increases the risk that such security interests or guarantees could be avoidable in bankruptcy.”

The rights of holders of Notes to the collateral may be adversely affected by other issues generally associated with the realization of security interests in collateral.

The security interest of the Notes Collateral Agent will be subject to practical challenges generally associated with the realization of security interests in collateral. For example, the Notes Collateral Agent may need to obtain the consent of third parties or make additional filings. If we are unable to obtain these consents or make these filings, the security interests may be invalid and the holders of the Notes will not be entitled to the collateral or any recovery with respect to the collateral. The Notes Collateral Agent may not be able to obtain any such consent. Further, the consents of any third parties may not be given when required to facilitate a foreclosure on such collateral. Accordingly, the Notes Collateral Agent may not have the ability to foreclose upon those assets. These requirements may limit the number of potential bidders for certain collateral in any foreclosure or other auction and may delay any sale, either of which events may have an adverse effect on the sale price of the collateral. Therefore, the practical value of realizing on the collateral may, without the appropriate consents and filings, be limited.

There are circumstances other than repayment or discharge of the Notes under which the collateral securing the Notes and guarantees will be released automatically, without your consent or the consent of the trustee.

Under various circumstances, collateral securing the Notes will be released automatically, including:

 

   

a sale, transfer or other disposition of such collateral (other than to Holdings or a subsidiary guarantor) in a transaction not prohibited under the indenture governing the Notes;

 

   

with respect to collateral held by a subsidiary guarantor, upon the release of such subsidiary guarantor from its guarantee;

 

   

with respect to collateral held by Holdings, upon the release or discharge of Holdings’ obligations under the Notes pursuant to the indenture governing the Notes;

 

   

pursuant to the Senior Lien Intercreditor Agreement with respect to enforcement actions by the holders of the first-priority obligations; and

 

   

if the Notes have been discharged or defeased pursuant to a legal defeasance or covenant defeasance under the indenture governing the Notes.

The guarantee of a subsidiary guarantor will be automatically released to the extent it is released in connection with a sale or other disposition of such subsidiary guarantor in a transaction not prohibited by the indenture governing the Notes. The indenture also permits us to designate one or more of our restricted subsidiaries that is a subsidiary guarantor of the Notes as an unrestricted subsidiary, which will result in the subsidiary guarantee of such guarantor being automatically released. If we designate a subsidiary guarantor as an unrestricted subsidiary for purposes of the indenture governing the Notes, all of the liens on any collateral owned by such subsidiary or any of its subsidiaries and any guarantees of the Notes by such subsidiary will be released under the indenture governing the Notes but not necessarily under the Credit Agreement and the aggregate value

 

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of the collateral securing the Notes will be reduced. In addition, the creditors of the unrestricted subsidiary and its subsidiaries will have a claim on the assets of such unrestricted subsidiary and its subsidiaries that is senior to the claim of the holders of the Notes.

We will, in most cases, have control over the collateral, and the sale of particular assets by us could reduce the pool of assets securing the Notes and the guarantees.

The collateral documents for the Notes will allow us to remain in possession of, retain exclusive control over, freely operate, and collect, invest and dispose of any income from, the collateral securing the Notes and the related guarantees. See “Description of the Notes—Security.”

If we become the subject of a bankruptcy proceeding, bankruptcy laws may limit your ability to realize value from the collateral.

The right of the Notes Collateral Agent to foreclose upon, repossess, and dispose of the collateral upon the occurrence of an event of default under the indenture governing the Notes is likely to be significantly impaired (or at a minimum delayed) by applicable bankruptcy or insolvency law if a bankruptcy case were to be commenced by or against Holdings or a subsidiary guarantor before the Notes Collateral Agent repossessed and disposed of the collateral (and sometimes even after). Upon the commencement of a case under the Bankruptcy Code or similar applicable law, a secured creditor such as the Notes Collateral Agent is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security previously repossessed from such debtor, without prior bankruptcy court approval, which may not be given or could be delayed. Moreover, the Bankruptcy Code permits the debtor to continue to retain and use cash and other collateral even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral as of the commencement of the bankruptcy or insolvency case and may include cash payments or the granting of additional or replacement security if and at such times as the bankruptcy court in its discretion determines that the value of the secured creditor’s interest in the collateral is declining during the pendency of the bankruptcy case. A bankruptcy court may determine that a secured creditor may not require compensation for a diminution in the value of its collateral if the value of the collateral exceeds the debt it secures.

In view of the lack of a precise definition of the term “adequate protection” and the broad discretionary power of a bankruptcy court, it is impossible to predict:

 

   

whether or when payments under the Notes could be made following the commencement of a bankruptcy case by Holdings or a subsidiary guarantor, or the length of any delay in making such payments;

 

   

whether or when the Notes Collateral Agent could or would repossess or dispose of the collateral;

 

   

the value of the collateral at the time of the commencement of the bankruptcy or insolvency; or

 

   

whether or to what extent holders of the Notes would be compensated for any delay in payment or loss of value of the collateral through the requirement of “adequate protection.”

Any disposition of the collateral during a bankruptcy or insolvency case would also require permission from the bankruptcy court (which may not be given or could be delayed). Furthermore, in the event a court determines the value of the collateral is not sufficient to repay all amounts due on debt which is to be paid first out of the proceeds of the collateral, the holders of the Notes would hold a secured claim only to the extent of the value of the collateral to which the holders of the Notes are entitled and an unsecured claim with respect to any shortfall. The Bankruptcy Code only permits the payment and accrual of post-petition interest, costs, expenses and attorneys’ fees or “adequate protection” to a secured creditor during a debtor’s bankruptcy case to the extent the value of its collateral is determined by the bankruptcy court to exceed the aggregate outstanding principal amount of the obligations secured by the collateral.

 

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Also, the Senior Lien Intercreditor Agreement will provide that, in the event of a bankruptcy by the Issuers or a subsidiary guarantor, the holders of the Notes will be subject to certain restrictions with respect to their ability to object to a number of important matters or to take other actions following the filing of a bankruptcy petition with respect to the collateral prior to the discharge of the obligations under the Bank Credit Facility. In particular, the Senior Lien Intercreditor Agreement will impose certain limitations on the holders of the Notes with respect to their rights to seek adequate protection with respect to the liens on the collateral, to object to proposed debtor-in-possession financing or the use of cash collateral that has been consented to by the lenders under the Bank Credit Facility, or to raise certain objections to any sale of the collateral that has been consented to by the lenders under the Bank Credit Facility. See “Description of the Notes—Security Documents—Senior Lien Intercreditor Agreement.”

Delivery of security interests in collateral or any guarantees after the Issue Date increases the risk that such security interests or guarantees could be avoidable in bankruptcy.

Certain collateral, including after-acquired property, will be secured after the Issue Date and certain guarantees may be granted and/or secured after the Issue Date. If the grantor of such security interest or such subsidiary guarantor were to become subject to a bankruptcy case after the Issue Date, any security interest in collateral or any guarantees delivered after the Issue Date would face a greater risk than security interests or guarantees in place on the Issue Date of being avoided by the pledgor or subsidiary guarantor (as debtor in possession) or by its trustee in bankruptcy or potentially by other creditors as a preference under bankruptcy law if certain events or circumstances exist or occur.

Specifically, security interests or antecedent debt or guarantees issued after the Issue Date may be treated under bankruptcy law as if they were delivered to secure or guarantee previously existing indebtedness. Any future pledge of collateral or future issuance of a guarantee in favor of the holders of the Notes, including pursuant to security documents or guarantees delivered in connection therewith after the date the Notes are issued, may be avoidable as a preference if, among other circumstances, (i) the pledgor or subsidiary guarantor is insolvent at the time of the pledge or the issuance of the guarantee, (ii) the pledge or the issuance of the guarantee permits the holders of the Notes to receive a greater recovery in a hypothetical Chapter 7 case than if the pledge or guarantee had not been given, and (iii) a bankruptcy case in respect of the pledgor or subsidiary guarantor is commenced within 90 days following the pledge or the perfection thereof or the issuance of the guarantee (as applicable), or, in certain circumstances, a longer period. Accordingly, if the Issuers or any subsidiary guarantor were to file for bankruptcy protection after the Issue Date of the Notes and (1) any liens granted after the Issue Date had been perfected, or (2) any guarantees issued after the Issue Date had been issued, less than 90 days before commencement of such bankruptcy case, such liens or guarantees are more likely to be avoided as a preference by the bankruptcy court than if delivered and promptly recorded on the Issue Date. To the extent that the grant of any such security interest and/or guarantee is avoided as a preference or otherwise, you would lose the benefit of the security interest and/or guarantee (as applicable).

In the event of a bankruptcy of an Issuer or any of the guarantors, holders of the Notes may be deemed to have an unsecured claim to the extent that the Issuers’ obligations in respect of the Notes exceed the fair market value of the collateral and the related guarantees.

In any bankruptcy proceeding with respect to the Issuers or any of the subsidiary guarantors, it is possible that the bankruptcy trustee, the debtor-in-possession or competing creditors will assert that the fair market value of the collateral with respect to the Notes on the date of the bankruptcy filing was less than the then-current principal amount of the Notes (including after taking into account any obligations under the Bank Credit Facility with respect to the collateral). Upon a finding by the bankruptcy court that the Notes are under-collateralized, the claims in the bankruptcy proceeding with respect to the Notes would be bifurcated between a secured claim and an unsecured claim, and the unsecured claim would not be entitled to the benefits of security in the collateral. In such event, the secured claims of the holders of the Notes would be limited to the value of the collateral.

 

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The consequences of a finding of under-collateralization would include, among other things, a lack of entitlement on the part of the holders of the Notes to receive post-petition interest, fees, and expenses and a lack of entitlement on the part of the unsecured portion of the Notes to receive “adequate protection” under federal bankruptcy laws, as discussed above. In addition, if any payments of post-petition interest had been made at the time of such a finding of under-collateralization, those payments could be recharacterized by the bankruptcy court as a reduction of the principal amount of the secured claim with respect to the Notes.

The collateral is subject to casualty risks, which may limit your ability to recover as a secured creditor if there are losses to the collateral, and which may have an adverse impact on our operations and results.

We maintain insurance or otherwise insure against certain hazards in a manner appropriate and customary for our business. There are, however, losses that may be not be insured, either because they are uninsurable or not economically insurable. If there is a total or partial loss of any of the pledged collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all the secured obligations, including the Notes, the Bank Credit Facility and related guarantees. In the event of a total or partial loss affecting any of our assets, certain items may not be easily replaced. Accordingly, even though there may be insurance coverage, the extended period needed to obtain replacement units or inventory may cause significant delays, which may have an adverse impact on our operations and results. In addition, certain zoning or other laws and regulations may prevent rebuilding substantially the same facilities in the event of a loss, which may have an adverse impact on our operations and results. Such adverse impacts may not be covered, or fully covered, by property or business interruption insurance.

Title insurance policies and surveys will not be obtained for any real property. As a result, any matters that could have been revealed by any survey or through the title insurance process could have a significant impact on the value of the collateral or any recovery under the mortgages.

Title insurance policies and surveys will not be obtained in connection with the mortgages against any of our real property. Accordingly, the mortgages will not have the benefit of (i) title insurance policies insuring our title to and the second priority of the liens of the mortgages with respect to any of the real property owned or leased by us and (ii) any surveys that would reveal encroachments, adverse possession claims, zoning or other restrictions that exist with respect to such real properties which could adversely affect the value or utility of such property securing the Notes. There can be no assurance that there does not exist a mechanics’ lien or other lien encumbering one or more of the real properties that is senior to the lien of any such mortgage, The existence of such liens could adversely affect the value of the real property securing the Notes as well as the ability of the collateral agent to realize or foreclose on such real property.

In addition, there can be no assurance that the legal descriptions attached to the mortgages (i) accurately describe and encumber the property intended to be mortgaged as security for the Notes, (ii) include all real property owned, leased or otherwise held by us or (iii) do not include real property not owned, leased or otherwise held by us.

Risks Related to the Exchange Offer

If you do not properly tender your Initial Notes, you will continue to hold unregistered Initial Notes and be subject to the same limitations on your ability to transfer Initial Notes.

We will only issue Exchange Notes in exchange for Initial Notes that are timely received by the exchange agent together with all required documents, including a properly completed and signed letter of transmittal. Therefore, you should allow sufficient time to ensure timely delivery of the Initial Notes and you should carefully follow the instructions on how to tender your Initial Notes. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of the Initial Notes. If you are eligible to participate in the Exchange Offer and do not tender your Initial Notes or if we do not accept your

 

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Initial Notes because you did not tender your Initial Notes properly, then, after we consummate the Exchange Offer, you will continue to hold Initial Notes that are subject to the existing transfer restrictions and will no longer have any registration rights or be entitled to any additional interest with respect to the Initial Notes. In general, you may only offer or sell the Initial Notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. Except as required by the Registration Rights Agreement, we do not currently anticipate that we will register under the Securities Act any Initial Notes that remain outstanding after the Exchange Offer. In addition, if you tender your Initial Notes for the purpose of participating in a distribution of the Exchange Notes, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the Exchange Notes; and if you are a broker-dealer that receives Exchange Notes for your own account in exchange for Initial Notes that you acquired as a result of market-making activities or any other trading activities, you will be required to acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus to purchasers) in connection with any resale, offer to resell or other transfer of those Exchange Notes.

We have agreed that, for a period of 180 days after the Exchange Offer is consummated, we will make additional copies of this prospectus and any amendment or supplement to this prospectus available to any broker-dealer for use in connection with any resales of the Exchange Notes.

After the Exchange Offer is consummated, if you continue to hold any Initial Notes, you may have difficulty selling them because there will be fewer Initial Notes outstanding. There may be no market for the Initial Notes after the Exchange Offer is consummated.

Trading markets for the Exchange Notes may not develop.

The Exchange Notes are new issues of securities with no established trading markets. We have not, nor do we intend to apply for, listing of any of the Exchange Notes on any national securities exchange or for inclusion of any of the Exchange Notes on any automated dealer quotation system.

The liquidity of any market for the Exchange Notes will depend upon various factors, including:

 

   

the number of holders of the Exchange Notes;

 

   

the interest of securities dealers in making a market for the Exchange Notes;

 

   

our ability to complete the Exchange Offer;

 

   

the overall market for high yield securities;

 

   

the interest of securities dealers in making a market in the Exchange Notes;

 

   

prevailing interest rates;

 

   

our financial performance or prospects; and

 

   

the prospects for companies in our industry generally.

Accordingly, we cannot assure you that a market or liquidity will develop for the Notes, nor can we make any assurances regarding the ability of holders of the Exchange Notes to sell their Exchange Notes, the amount of Exchange Notes to be outstanding following the Exchange Offer or the price at which the Exchange Notes might be sold. As a result, the market price of the Exchange Notes could be adversely affected. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to exchange the Notes. We cannot assure you that the market for the Exchange Notes, if any, will not be subject to similar disruptions. Any such disruptions may adversely affect you as a holder of the Exchange Notes.

 

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The issuance of the Exchange Notes may adversely affect the market for the Initial Notes.

To the extent the Initial Notes are tendered and accepted in the Exchange Offer, the trading market for the untendered and tendered but unaccepted Initial Notes could be adversely affected. Because we anticipate that most holders of the Initial Notes will elect to exchange their Initial Notes for Exchange Notes due to the absence of restrictions on the resale of the Exchange Notes under the Securities Act, we anticipate that the liquidity of the market for any Initial Notes remaining after the completion of this Exchange Offer may be substantially limited. There may be no market for the Initial Notes after the Exchange Offer is consummated. Please refer to the section in this prospectus entitled “The Exchange Offer—Your Failure to Participate in the Exchange Offer Will Have Adverse Consequences.”

Some persons who participate in the Exchange Offer must deliver a prospectus in connection with resales of the Exchange Notes.

Based on interpretations of the staff of the Commission contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the Exchange Notes without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under “Plan of Distribution,” you will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your Exchange Notes. In these cases, if you transfer any Exchange Note without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your Exchange Notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability.

 

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USE OF PROCEEDS

We will not receive any cash proceeds from the issuance of the Exchange Notes in exchange for the outstanding Initial Notes. We are making this exchange solely to satisfy our obligations under the Registration Rights Agreement. In consideration for issuing the Exchange Notes, we will receive Initial Notes in like aggregate principal amount which we will submit to the trustee for cancellation.

 

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CAPITALIZATION

The following table sets forth the cash and cash equivalents and capitalization as of June 30, 2018 for the Company.

You should read this table in conjunction with the financial statements and the related notes included elsewhere in this prospectus, as well as the sections entitled “Use of Proceeds,” “Selected Historical Consolidated Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

(in thousands)    As of
June 30,
2018
 

Cash and cash equivalents

   $ 78,860  
  

 

 

 

Long-term debt, including current portion:

  

Bank Credit Facility(1)

   $ 240,000  

4.20% Building Loan, including current portion

     10,778  

Stone Notes

     6,060  

Initial Notes

     390,868  
  

 

 

 

Total long-term debt, including current portion

     647,706  

Total stockholders’ equity

     685,845  
  

 

 

 

Total capitalization

   $ 1,333,551  
  

 

 

 

 

(1)

As of June 30, 2018, the Bank Credit Facility had approximately $354.0 million of undrawn commitments (taking into account $6.0 million of letters of credit and $240.0 million drawn from the Bank Credit Facility).

 

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges on a historical basis for the periods indicated. The ratio of earnings to fixed charges is computed by dividing fixed charges into net income (loss) before provision (benefit) for income taxes plus fixed charges less capitalized interest. Fixed charges consist of interest expense (both expensed and capitalized), amortization of debt costs and that portion of rental expense we believe reflects a reasonable approximation of the interest component of rent expense. The Company commenced commercial operations on February 6, 2013, when it acquired all of the equity of Energy Resource Technology GOM, LLC and its subsidiary (the “Talos Energy Predecessor”) from Helix Energy Solutions Group, Inc. (the “ERT Acquisition”). Prior to the ERT Acquisition, the Company had incurred only certain general and administrative expenses associated with the start-up of its operations.

 

                  Talos Energy
Predecessor
 
     Six Months Ended
June 30,
     Year Ended December 31,     January 1,
2013 through
February 5,
2013
 
       2018          2017        2017      2016      2015      2014      2013  

Ratio of earnings to fixed charges(1)

     —          2.49x        —          —          —          6.76x        2.56x       —    

 

(1)

For the six months ended June 30, 2018, earnings were inadequate to cover fixed charges by $97.9 million. For the years ended December 31, 2017, 2016 and 2015, earnings were inadequate to cover fixed charges by $63.5 million, $208.5 million and $650.6 million, respectively. For the predecessor period from January 1, 2013 through February 5, 2013, earnings were inadequate to cover fixed charges by $0.9 million.

 

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SELECTED HISTORICAL FINANCIAL DATA

The following table sets forth the selected consolidated historical financial data for the Company and Talos Energy Predecessor (defined below) as of and for the periods ended on the dates indicated below. The unaudited selected historical statement of operations data for the six months ended June 30, 2018 and 2017, and the unaudited selected historical balance sheet data as of June 30, 2018 have been derived from the unaudited condensed consolidated financial statements for the interim period ended June 30, 2018, which are included elsewhere in this prospectus. The selected historical statement of operations data for the years ended December 31, 2017, 2016 and 2015, and the selected historical balance sheet data as of December 31, 2017 and 2016, have been derived from our audited consolidated financial statements and related notes for the year ended December 31, 2017, which are included elsewhere in this prospectus. The selected historical statement of operations data for the years ended December 31, 2014 and 2013, and the selected historical balance sheet data as of December 31, 2015, 2014 and 2013, have been derived from our audited consolidated financial statements, which have not been included in this prospectus. The selected historical consolidated financial data for the period from January 1, 2013 through February 5, 2013 of the Talos Energy Predecessor were derived from the audited historical financial statements of the Talos Energy Predecessor, which have not been included in this prospectus. The Company’s consolidated financial statements have been prepared in accordance with GAAP. The Company’s results of operations in any period may not necessarily be indicative of the results that may be expected for any future period. See “Risk Factors” beginning on page 12 of this prospectus.

The selected consolidated historical financial information should be read in conjunction with our financial statements and the related notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 59 of this prospectus.

 

                Talos Energy
Predecessor
 
    Six Months
Ended June 30,
    Year Ended December 31,     January 1,
2013 through
February 5,
2013
 

(in millions, except per common share amounts)

  2018     2017     2017     2016     2015     2014     2013  

Statement of Operations

               

Total revenue

  $ 349.8     $ 197.3     $ 412.8     $ 258.8     $ 315.6     $ 561.6     $ 413.6     $ 49.1  

Operating income (loss)

    87.8       13.6       45.3       (80.7     (777.7     109.1       74.6       14.2  

Net income (loss)

    (97.9     59.1       (62.9     (208.1     (646.7     309.4       57.9       (0.9

Basic and diluted net income (loss) per common share

  $ (2.59   $ 1.89     $ (2.01   $ (7.99   $ (26.20   $ 15.20     $ 2.98    

 

                Talos Energy
Predecessor
 
    As of
June 30,

2018
    As of December 31,     As of
February 5,
2013
 

(in millions)

  2017     2016     2015     2014     2013  

Balance Sheet

               

Total assets

  $ 2,284.1     $ 1,239.3     $ 1,212.3     $ 1,194.8     $ 1,697.2     $ 948.6    

Total debt(1)

    628.4       697.6       701.2       690.2       595.5       279.5    

Total stockholders’ equity (deficit)

    685.8       (54.1     7.0       120.9       690.5       378.4    

 

(1)

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The amendment changes the presentation of long-term debt issuance costs in the financial statements, and was adopted by Talos Energy during the first quarter of 2016 and applied retrospectively to December 31, 2015, 2014 and 2013 as presented above.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

Unless otherwise indicated or the context otherwise requires, references herein to the “Company,” “we,” “us,” “our” and “Talos,” refer to, from and after the Closing Date, Talos Energy Inc. and its consolidated subsidiaries and prior to the Closing Date, Talos Energy LLC and its consolidated subsidiaries.

Our Business

We are a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

On the Closing Date, the following Transactions, among others, occurred: (i) Stone underwent a reorganization pursuant to which Merger Sub merged with and into Stone, with Stone continuing as the surviving corporation and our direct wholly-owned subsidiary (the “Merger”) and each share of Stone’s common stock outstanding immediately prior to the Merger (other than treasury shares held by Stone, which were cancelled for no consideration) was converted into the right to receive one share of our common stock, par value $0.01 (the “Common Stock”); and (ii) in a series of contributions, the Apollo Funds and Riverstone Funds contributed all of the equity interests in Talos Production LLC (which at that time owned 100% of the equity interests in Talos Energy LLC) to us in exchange for an aggregate of 31,244,085 shares of our common stock (the “Sponsor Equity Exchange”). Substantially concurrent with the consummation of the Transactions, we changed our name from Sailfish Energy Holdings Corporation to Talos Energy Inc.

Concurrently with the consummation of the Transactions contemplated by the Transaction Agreement, we consummated the Transactions contemplated by the Exchange Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes due 2022 (the “9.75% Senior Notes”) issued by Talos Production LLC and Talos Production Finance, Inc. (together, the “Talos Issuers”) to us in exchange for an aggregate of 2,874,049 shares of our common stock; (ii) the holders of second lien bridge loans (“11.00% Bridge Loans”) issued by the Talos Issuers exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of 11.00% Second-Priority Senior Secured Notes due 2022 of the Talos Issuers (the “Initial Notes”) and (iii) the Franklin Noteholders and the MacKay Noteholders exchanged their 7.50% Senior Secured Notes due 2022 issued by Stone (“7.50% Stone Senior Notes”) for $137.4 million aggregate principal amount of Initial Notes.

As a result of the Closing, on the Closing Date, the former stakeholders of Talos Energy LLC held approximately 63% of our then outstanding common stock and the former stockholders of Stone held approximately 37% of our then outstanding common stock.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy our capital as efficiently as possible.

We plan to opportunistically expand our asset base by evaluating the robust supply of acquisition opportunities in the Gulf of Mexico. The acquisition strategy is focused on deep and shallow water assets with a geological setting which we believe can benefit from our access to an extensive seismic database and our

 

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reprocessing expertise to reevaluate the acquired assets. We expect to target acquisitions involving assets with physical infrastructure that will allow us to focus on additional drilling opportunities. By applying a disciplined valuation methodology, we seek to reduce the risk of acquired property underperformance while maintaining potential for higher returns on our investment. In addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are suitable for our operational and technical expertise to the extent we believe it will increase our reserves and enhance returns on our investment and long-term growth prospects.

Recent Developments

On July 10, 2018, our Mt. Providence well began producing 60 days ahead of the originally scheduled completion date of early September. The Mt. Providence well was successfully drilled in January 2018 by Stone after entering into the Transaction Agreement, but before the Closing. We completed the well and connected it to the 100% Talos owned Pompano platform in our Mississippi Canyon Complex within six months of concluding drilling operations. As of August 2018, the well is currently producing 4,200 Boepd. We are the operator with a 100% working interest.

We drilled the first two wells in our 2018 Shelf drilling program, SS224 E21ST and EW306 A20, during the first and second quarters of 2018. As of August 2018, the SS224 E21ST well is currently producing at approximately 700 Boepd. EW306 A20 was discovered and we continued drilling to deeper target sands with another discovery in July 2018. As of August 2018, this well is currently producing 2,200 Boepd.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

Stone Combination

As previously described, Stone and Talos Energy LLC became our wholly-owned subsidiaries on the Closing Date. Prior to the Closing Date, Talos Energy Inc. had not conducted any material activities other than those incident to our formation and certain matters contemplated by the Transaction Agreement. Talos Energy LLC is the acquirer of Stone for financial reporting and accounting purposes. Talos Energy LLC was considered the accounting acquirer in the Transactions under GAAP. Accordingly, the historical financial and operating data, which cover periods prior to the Closing Date, reflects the assets, liabilities and operations of Talos Energy LLC prior to the Closing Date and does not reflect the assets, liabilities and operations of Stone prior to the Closing Date. In addition, we incurred material costs associated with the Transactions that are reflected in our historical results of operations for periods prior to the Closing Date, and Talos Energy LLC did not incur United States federal income tax expense or the incremental expenses associated with being a public company.

Transaction Expenses

We have incurred and will continue to incur transaction related and restructuring costs associated with the Stone Combination and the integration of the businesses of Stone and Talos that are not reflected in our comparative historical results of operations.

Public Company and Income Tax Expenses

Prior to the Stone Combination, Talos Energy LLC was a partnership for U.S. federal income tax purposes and was not subject to U.S. federal income tax or state income tax (in most states). As such, Talos Energy LLC was not a taxpaying entity for U.S. federal income tax purposes and accordingly, did not recognize any expenses for such states. In connection with completing the Stone Combination, Talos Energy LLC was contributed to the Company, which is subject to U.S. federal and state income taxes.

Acquisition History

Sojitz Acquisition. On December 20, 2016, we consummated the Sojitz Acquisition whereby we purchased an additional 15% working interest in the Phoenix Field from Sojitz Energy Venture, Inc. (“Sojitz”) for

 

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approximately $85.8 million in cash and the assumption of certain asset retirement obligations, subject to customary post-closing adjustments. The purchase price was funded by a $93.8 million ($91.9 million net of $1.9 million of transaction fees) contribution from the Sponsors. Additionally, we entered into a contingent consideration arrangement in the form of an earn-out equal to 5% of the acquired property’s monthly net profit if our realized oil price is greater than $65.00 per Bbl in a given month. The maximum payout under the earn-out is $10.0 million and has an indefinite life pursuant to the purchase and sale agreement.

DGE Acquisition. On April 8, 2015, we entered into a supplemental agreement and first amendment to a previous participation agreement dated July 1, 2014 with Deep Gulf Energy III, LLC (“DGE”) pursuant to which we completed the DGE Acquisition by acquiring a 25% working interest in the Motormouth discovery located in the Phoenix Field in exchange for $38.5 million in cash, assuming estimated asset retirement obligations and purchasing the right to participate in an additional 10% working interest in its Tornado exploration prospect. The working interest acquired from DGE was previously farmed out to DGE on July 1, 2014 in order for DGE to participate in the Motormouth exploration prospect. The Sponsors made a $75.0 million ($73.5 million net of $1.5 million of transaction fees) equity contribution in April 2015, of which a portion was used to fund the purchase price.

GCER Acquisition. On March 31, 2015, we completed the GCER Acquisition whereby we purchased all the issued and outstanding membership interests of Gulf Coast Energy Resources, LLC (“GCER”) from Warburg Pincus Private Equity (E&P) X-A, LP and its affiliates, Q-GCER (V) Investment Partners and GCER management and independent directors. Through this acquisition, we acquired all of GCER’s oil and natural gas assets which consist of proved and unproved property primarily located in the Gulf of Mexico Shelf and lower Gulf Coast areas along with current and other long-term assets. As consideration for the acquired membership interests in GCER, we assumed $55.0 million in long-term debt as well as the estimated asset retirement obligations and current liabilities as of March 31, 2015. Additionally, we entered into a contingent consideration arrangement in the form of an earn-out, valued at $0.1 million, if the oil and natural gas assets meet certain return on investment targets within the subsequent five years. We incurred approximately $0.8 million of transaction fees which were expensed and reflected in general and administrative expense during 2015. We refer to the acquisition of all the issued and outstanding membership interests in GCER as the “GCER Acquisition.”

We intend to continue to selectively acquire companies and producing properties based on disciplined valuations of proved reserves. In addition, we believe that the Gulf of Mexico continues to represent an attractive buyer’s market, which should facilitate this acquisition strategy. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur substantial debt or issue additional equity securities to fund future acquisitions.

For certain periods, we have provided additional analysis for comparability of results and to aid in the analysis and understanding of our operating performance period over period. Any non-GAAP analysis is provided as supplemental financial information to our GAAP results and is not intended to be a substitute for our reported GAAP results.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices. Historically, the markets for oil and natural gas have been volatile. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production. Oil, natural gas and NGL prices are subject to wide fluctuations in response to relatively minor changes in supply and demand.

BOEM Bonding Requirements. In order to cover the various decommissioning obligations of lessees on the Outer Continental Shelf (“OCS”), the Bureau of Ocean Energy Management (“BOEM”) generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we

 

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can continue to obtain bonds or other surety in all cases. As many BOEM regulations are being reviewed by the agency, we may be subject to additional financial assurance requirements in the future. For example, in July 2016, the BOEM issued Notice to Lessees and Operators (“NTL”) #2016-N01 (the “2016 NTL”) to clarify the procedures and guidelines that BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, rights of way (“ROWs”) and rights of use and easement (“RUEs”). The 2016 NTL became effective in September 2016, but the BOEM has since extended indefinitely the start date for implementing this NTL so as to provide the BOEM with time to review its complex financial assurance program. This extension currently remains in effect. We remain in active discussions with government regulators and industry peers with regard to any future rulemaking and financial assurance requirements. Notwithstanding the BOEM’s 2016 NTL, the BOEM may also bolster its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us as a result of the 2016 NTL, to the extent implemented, as well as any other future BOEM directives, or any other changes to the BOEM’s rules applicable to our or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows, and results of operations.

Deepwater Operations. We have interests in six deepwater fields in the Gulf of Mexico, only five of which we operate (Bushwood, Phoenix, Amberjack, Pompano and Ram Powell). Operations in the deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan. We maintain a Regional Oil Spill Response 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 Bureau of Safety and Environmental Enforcement (“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. Additionally, these plans are tested and drills are conducted periodically at all levels.

Hurricanes. Since our operations are in the Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage for property damage to our facilities for hurricanes has become less effective due to rising retentions and limitations on named windstorm coverage and has been difficult to obtain at times in recent years. 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.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

 

   

production volumes;

 

   

realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

 

   

lease operating expenses;

 

   

capital expenditures; and

 

   

Adjusted EBITDA.

Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include

 

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the effects of derivatives, which are reported in price risk management activities income in our consolidated statements of operations. The following table presents a breakout of each revenue component:

 

     Six Months Ended
June 30,
    Year Ended December 31,  
     2018     2017       2017         2016         2015    

Revenue breakout:

          

Oil revenue

     88     82     83     76     77

Natural gas revenue

     8     13     12     17     18

NGL revenue

     4     4     4     4     3

Other

     —       1     1     3     2

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs. The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude and Louisiana Light Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil and natural gas sales prices for the periods indicated.

 

     Six Months Ended
June 30,
     Year Ended December 31,  
     2018      2017      2017      2016      2015  

Oil:

              

NYMEX WTI High per Bbl

   $ 69.98      $ 53.46      $ 57.95      $ 52.17      $ 59.83  

NYMEX WTI Low per Bbl

     62.18        45.20        45.20        30.62        37.33  

Average NYMEX WTI per Bbl

     65.37        50.10        50.95        43.32        48.80  

Average Oil Sales Price per Bbl
(including commodity derivatives)

     54.12        51.28        52.46        68.46        78.42  

Average Oil Sales Price per Bbl
(excluding commodity derivatives)

     65.75        46.85        48.92        38.55        47.31  

Natural Gas:

              

NYMEX Henry Hub High per MMBtu

   $ 3.63      $ 3.93      $ 3.93      $ 3.23      $ 3.19  

NYMEX Henry Hub Low per MMBtu

     2.64        2.63        2.63        1.71        2.03  

Average NYMEX Henry Hub per MMBtu

     2.90        3.25        3.11        2.46        2.66  

Average Natural Gas Sales Price per Mcf
(including commodity derivatives)

     2.94        2.87        2.93        3.24        3.56  

Average Natural Gas Sales Price per Mcf
(excluding commodity derivatives)

     2.90        3.07        3.00        2.25        2.56  

 

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     Six Months Ended
June 30,
    Year Ended December 31,  
     2018     2017     2017     2016     2015  

NGLs:

          

NGL Realized Price as a % of Average NYMEX WTI

     41     42     46     36     37

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, from time to time we enter into commodity derivative arrangements for our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined at our discretion and may be different from what we have done on a historical basis.

Expenses

Direct lease operating expense. Direct lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our direct lease operating expense. In July 2016, we executed a new contract for the HP-I accounted for as a capital lease, thus reducing the amount recorded as direct lease operating expenses going forward. For more information, see Note 10 to our consolidated financial statements for the fiscal year ended December 31, 2017 and Note 11 to our unaudited interim condensed consolidated financial statements, both included elsewhere in this prospectus. Direct lease operating expense does not include general and administrative expenses.

Insurance expense. Insurance expense consists of the cost of insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent based on our estimated loss potential. Our significant domestic and international policies include general liability, physical damage to our oil and gas properties, operational control of well, named Gulf of Mexico windstorm and oil pollution.

Production taxes. Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Workover and maintenance expense. Workover and maintenance expense consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period to period.

Depreciation, depletion and amortization expense. Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See “—Critical Accounting Policies and Estimates—Oil and Natural Gas Properties” for further discussion.

Write-down of oil and natural gas properties. Write-down of oil and natural gas properties occurs when our capitalized oil and natural gas costs exceeds the full cost ceiling calculated as the present value of future net

 

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revenues from proved reserves, discounted at 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. See “—Critical Accounting Policies and Estimates, Oil and Natural Gas Properties” for further discussion.

Accretion expense. We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

General and administrative expense. General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity based compensation expense, Sponsor fees, audit and other fees for professional services and legal compliance.

Interest expense. We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price risk management activities. We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

 

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Results of Operations

Comparison of the Six Months Ended June 30, 2018 and 2017

The information below provides the financial results and an analysis of significant variances in these results for the six months ended June 30, 2018 and 2017 (in thousands):

 

     Six Months Ended
June 30,
             
     2018     2017     Change     % Change  

Revenues:

        

Oil revenue

   $ 307,854     $ 162,487     $ 145,367       89

Natural gas revenue

     29,171       26,062       3,109       12

NGL revenue

     12,731       7,069       5,662       80

Other

     —         1,632       (1,632     (100 )% 
  

 

 

   

 

 

   

 

 

   

Total revenue

     349,756       197,250       152,506       77

Operating expenses:

        

Direct lease operating expense

     58,975       56,735       2,240       4

Insurance

     6,934       5,409       1,525       28

Production taxes

     955       645       310       48
  

 

 

   

 

 

   

 

 

   

Total lease operating expense

     66,864       62,789       4,075       6

Workover and maintenance expense

     24,619       17,047       7,572       44

Depreciation, depletion and amortization

     116,766       76,088       40,678       53

Accretion expense

     14,252       10,509       3,743       36

General and administrative expense

     39,460       17,216       22,244       129
  

 

 

   

 

 

   

 

 

   

Total operating expenses

     261,961       183,649       78,312       43
  

 

 

   

 

 

   

 

 

   

Operating income

     87,795       13,601       74,194       546

Interest expense

     (41,420     (39,577     (1,843     (5 )% 

Price risk management activities income (expense)

     (143,152     84,888       (228,040     (269 )% 

Other income (expense)

     (1,078     157       (1,235     (787 )% 
  

 

 

   

 

 

   

 

 

   

Total other income (expense)

     (185,650     45,468       (231,118     (508 )% 
  

 

 

   

 

 

   

 

 

   

Income (loss) before income taxes

     (97,855     59,069       (156,924     (266 )% 

Income tax expense (benefit)

     —         —         —         —  
  

 

 

   

 

 

   

 

 

   

Net income (loss)

   $ (97,855   $ 59,069     $ (156,924     (266 )% 
  

 

 

   

 

 

   

 

 

   

 

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The table below provides additional detail of our oil, natural gas and NGL production volumes and sales prices per unit.

 

     Six Months Ended
June 30,
        
     2018     2017      Change  

Oil production volume (MBbls)

     4,682       3,468        1,214  

Average daily oil production volume (MBblpd)

     25.9       19.2        6.7  

Oil sales revenue (in thousands)

   $ 307,854     $ 162,487      $ 145,367  

Average oil sales price per Bbl (including commodity derivatives)

   $ 54.12     $ 51.28      $ 2.84  

Average oil sales price per Bbl (excluding commodity derivatives)

   $ 65.75     $ 46.85      $ 18.90  

Average NYMEX WTI price per Bbl

   $ 65.37     $ 50.10      $ 15.27  

Increase in oil sales revenue due to:

       

Change in net realized prices (in thousands)

   $ 88,491       

Change in production volume (in thousands)

     56,876       
  

 

 

      

Total increase in oil sales revenue (in thousands)

   $ 145,367       
  

 

 

      

Natural gas production volume (MMcf)

     10,069       8,498        1,571  

Average daily natural gas production volume (MMcfpd)

     55.6       47.0        8.6  

Natural gas sales revenue (in thousands)

   $ 29,171     $ 26,062      $ 3,109  

Average natural gas sales price per Mcf (including commodity derivatives)

   $ 2.94     $ 2.87      $ 0.07  

Average natural gas sales price per Mcf (excluding commodity derivatives)

   $ 2.90     $ 3.07      $ (0.17

Average NYMEX Henry Hub price per MMBtu

   $ 2.90     $ 3.25      $ (0.35

Increase in natural gas sales revenue due to:

       

Change in net realized prices (in thousands)

   $ (1,714     

Change in production volume (in thousands)

     4,823       
  

 

 

      

Total increase in natural gas sales revenue (in thousands)

   $ 3,109       
  

 

 

      

NGL production volume (MBbls)

     471       337        134  

Average daily NGL production volume (MBblpd)

     2.6       1.9        0.7  

NGL sales revenue (in thousands)

   $ 12,731     $ 7,069      $ 5,662  

Average NGL sales price per Bbl

   $ 27.03     $ 20.98      $ 6.05  

Increase in NGL sales revenue due to:

       

Change in net realized prices (in thousands)

   $ 2,851       

Change in production volume (in thousands)

     2,811       
  

 

 

      

Total increase in NGL sales revenue (in thousands)

   $ 5,662       
  

 

 

      

Total production volume (MBoe)(1)

     6,831       5,222        1,609  

Average daily total production volume (MBoepd)(1)

     37.7       28.9        8.8  

Price per Boe(1) (including commodity derivatives)

   $ 43.29     $ 40.08      $ 3.21  

Price per Boe(1) (excluding commodity derivatives)

   $ 51.20     $ 37.46      $ 13.74  

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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The following table highlights operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the six months ended June 30, 2018 and 2017 (in thousands, except per Boe data):

 

     Six Months Ended June 30,  
     2018      2017  
     Total      Per Boe(1)      Total      Per Boe(1)  

Lease operating expenses:

           

Direct lease operating expense

   $ 58,975      $ 8.63      $ 56,735      $ 10.86  

Insurance

     6,934        1.02        5,409        1.04  

Production taxes

     955        0.14        645        0.12  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total lease operating expenses

     66,864        9.79        62,789        12.02  

Depreciation, depletion and amortization

     116,766        17.09        76,088        14.57  

General and administrative expense

     39,460        5.78        17,216        3.30  

Other operating expenses:

           

Workover and maintenance expense

     24,619        3.60        17,047        3.26  

Accretion expense

     14,252        2.09        10,509        2.01  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other operating expenses

     38,871        5.69        27,556        5.27  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 261,961      $ 38.35      $ 183,649      $ 35.16  
  

 

 

    

 

 

    

 

 

    

 

 

 

Revenue. Total revenue for the six months ended June 30, 2018 was $349.8 million compared to $197.3 million for the six months ended June 30, 2017, an increase of approximately $152.5 million, or 77%. Oil revenue increased approximately $145.4 million, or 89%, during the six months ended June 30, 2018. This increase was primarily due to an increase of $18.90 per Bbl in our realized oil sales price and a 6.7 MBblpd increase in oil production volumes. The increase in oil production volumes was attributable to 4.8 MBblpd from the Stone Combination and 3.3 MBblpd from the Tornado II well in the Phoenix Field which commenced initial production in December 2017. This was partially offset by 0.6 MBblpd deferred production from the Phoenix Field for unplanned third party downtime for the HP-I as determined by Helix.

Natural gas revenue increased approximately $3.1 million, or 12%, during the six months ended June 30, 2018. This increase was due to an 8.7 MMcfpd increase in gas volumes, 11.4 MMcfpd of which was attributable to the Stone Combination. This was partially offset by a $0.17 per Mcf decrease in our realized gas sales price.

NGL revenue increased approximately $5.7 million, or 80%, during the six months ended June 30, 2018. This increase was due to an increase of $6.05 in our realized NGL sales price and a 0.7 MBblpd increase in NGL volumes, 0.6 MBblpd of which was attributable to the Stone Combination.

Lease operating expense. Total lease operating expense for the six months ended June 30, 2018 was $66.9 million compared to $62.8 million for the six months ended June 30, 2017, an increase of approximately $4.1 million, or 6%. This increase was primarily related to $9.9 million of lease operating expense in connection with the Stone Combination, partially offset by a $6.6 million decrease due to additional reimbursements related to our production handling agreements primarily in the Phoenix Field.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the six months ended June 30, 2018 was $116.8 million compared to $76.1 million for the six months ended June 30, 2017, an increase of approximately $40.7 million, or 53%. This increase is primarily due to a $2.56 per Boe, or 18% increase in the depletion rate on our proved oil and natural gas properties during the six months ended June 30, 2018. Depletion on a per Boe basis increased primarily due to an increase in proved properties related to the Stone Combination and higher estimated future development costs related to proved undeveloped reserves in the Phoenix Field.

 

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General and administrative expense. General and administrative expense for the six months ended June 30, 2018 was $39.5 million compared to $17.2 million for the six months ended June 30, 2017, an increase of approximately $22.2 million, or 129%. This increase was primarily attributable to $20.1 million in transaction related costs related to the Stone Combination and additional general and administrative expenses as a result of the combined company.

Other operating expense. Other operating expense for the six months ended June 30, 2018 was $38.9 million compared to $27.6 million for the six months ended June 30, 2017, an increase of approximately $11.3 million, or 41%. This increase was primarily related to an increase of $4.5 million and $4.1 million in workover and maintenance expense and accretion expense, respectively, in connection with the Stone Combination. This increase also relates to a $3.0 million increase in repairs and maintenance during the six months ended June 30, 2018 primarily related to $1.3 million in repairs on SMI 130 and inspection and reconnection support in the Phoenix Field of $1.2 million.

Price risk management activities. Price risk management activities for the six months ended June 30, 2018 resulted in a $143.2 million expense compared to income of $84.9 million for the six months ended June 30, 2017. The change of approximately $228.0 million was attributable to a $160.3 million decrease in the fair value of our open derivative contracts and a $67.7 million decrease in cash settlement gains for the six months ended June 30, 2018. These unrealized gains on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our condensed consolidated statements of operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Comparison of the Year Ended December 31, 2017 and 2016

The information below provides the financial results and an analysis of significant variances in these results for the year ended December 31, 2017 and 2016 (in thousands):

 

     Year Ended December 31,      Change      % Change  
     2017      2016  

Revenues:

           

Oil revenue

   $ 344,781      $ 197,583      $ 147,198        74

Natural gas revenue

     48,886        42,705        6,181        14

NGL revenue

     16,658        9,532        7,126        75

Other

     2,503        8,934        (6,431      (72 )% 
  

 

 

    

 

 

    

 

 

    

Total revenue

     412,828        258,754        154,074        60

Operating expenses:

           

Direct lease operating expense

     109,180        124,360        (15,180      (12 )% 

Insurance

     10,743        13,101        (2,358      (18 )% 

Production taxes

     1,460        1,958        (498      (25 )% 
  

 

 

    

 

 

    

 

 

    

Total lease operating expense

     121,383        139,419        (18,036      (13 )% 

Workover and maintenance expense

     32,825        24,810        8,015        32

Depreciation, depletion and amortization

     157,352        124,689        32,663        26

Accretion expense

     19,295        21,829        (2,534      (12 )% 

General and administrative expense

     36,673        28,686        7,987        28
  

 

 

    

 

 

    

 

 

    

Total operating expenses

     367,528        339,433        28,095        8
  

 

 

    

 

 

    

 

 

    

Operating income (loss)

     45,300        (80,679      125,979        156

Interest expense

     (80,934      (70,415      (10,519      (15 )% 

Price risk management activities expense

     (27,563      (57,398      29,835        52

Other income

     329        405        (76      (19 )% 
  

 

 

    

 

 

    

 

 

    

Net loss

   $ (62,868    $ (208,087    $ 145,219        70
  

 

 

    

 

 

    

 

 

    

 

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The table below provides additional detail of our production volumes and sales prices per unit.

 

     Year Ended December 31,      Change  
     2017     2016  

Oil production volume (MBbls)

     7,048       5,126        1,922  

Oil sales revenue (in thousands)

   $ 344,781     $ 197,583      $ 147,198  

Average oil sales price per Bbl (including commodity derivatives)

   $ 52.46     $ 68.46      $ (16.00

Average oil sales price per Bbl (excluding commodity derivatives)

   $ 48.92     $ 38.55      $ 10.37  

Average NYMEX WTI price per Bbl

   $ 50.95     $ 43.32      $ 7.63  

Increase in oil sales revenue due to:

       

Change in net realized prices (in thousands)

   $ 73,105       

Change in production volume (in thousands)

     74,093       
  

 

 

      

Total increase in oil sales revenue (in thousands)

   $ 147,198       
  

 

 

      

Natural gas production volume (MMcf)

     16,308       19,001        (2,693

Natural gas sales revenue (in thousands)

   $ 48,886     $ 42,705      $ 6,181  

Average natural gas sales price per Mcf (including commodity derivatives)

   $ 2.93     $ 3.24      $ (0.31

Average natural gas sales price per Mcf (excluding commodity derivatives)

   $ 3.00     $ 2.25      $ 0.75  

Average NYMEX Henry Hub price per MMBtu

   $ 3.11     $ 2.46      $ 0.65  

Increase in natural gas sales revenue due to:

       

Change in net realized prices (in thousands)

   $ 12,240       

Change in production volume (in thousands)

     (6,059     
  

 

 

      

Total increase in natural gas sales revenue (in thousands)

   $ 6,181       
  

 

 

      

NGL production volume (MBbls)

     706       603        103  

NGL sales revenue (in thousands)

   $ 16,658     $ 9,532      $ 7,126  

Average NGL sales price per Bbl

   $ 23.59     $ 15.81      $ 7.78  

Increase in NGL sales revenue due to:

       

Change in net realized prices (in thousands)

   $ 5,498       

Change in production volume (in thousands)

     1,628       
  

 

 

      

Total increase in NGL sales revenue (in thousands)

   $ 7,126       
  

 

 

      

Total production volume (MBoe)(1)

     10,472       8,896        1,576  

Price per Boe(1) (including commodity derivatives)

   $ 41.46     $ 47.44      $ (5.98

Price per Boe(1) (excluding commodity derivatives)

   $ 39.18     $ 28.08      $ 11.10  

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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The following table highlights operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2017 and 2016 (in thousands, except per Boe data):

 

     Year Ended December 31,  
     2017      2016  
     Total      Per Boe(1)      Total      Per Boe(1)  

Lease operating expenses:

           

Direct lease operating expense

   $ 109,180      $ 10.43      $ 124,360      $ 13.98  

Insurance

     10,743        1.03        13,101        1.47  

Production taxes

     1,460        0.14        1,958        0.22  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total lease operating expenses

     121,383        11.60        139,419        15.67  

Depreciation, depletion and amortization

     157,352        15.03        124,689        14.02  

General and administrative expense

     36,673        3.50        28,686        3.22  

Other operating expenses:

           

Workover and maintenance expense

     32,825        3.13        24,810        2.79  

Accretion expense

     19,295        1.84        21,829        2.45  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other operating expenses

     52,120        4.97        46,639        5.24  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 367,528      $ 35.10      $ 339,433      $ 38.15  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Revenue. Total revenue for the year ended December 31, 2017 was $412.8 million compared to $258.8 million for the year ended December 31, 2016, an increase of $154.0 million, or 60%. Oil revenue increased by $147.2 million, or 74%, during the year ended December 31, 2017. This increase was primarily due to an increase of $10.37 per Bbl in our realized oil sales price and 5.3 MBbl per day increase in production volumes. The increase in production volumes primarily related to a 6.2 MBbl per day increase from the Tornado well, GC 281 #1ST (T-9) in the Phoenix Field. Initial production commenced in October 2016.

Natural gas revenue increased by $6.2 million, or 14%, during the year ended December 31, 2017. The increase in natural gas revenue was due to a $0.75 per Mcf increase in our realized average natural gas sales price. This increase was offset by a 7.4 MMcf per day decrease in production during the year ended December 31, 2017 primarily due to third party pipeline maintenance and weather related downtime.

Other revenue decreased by $6.4 million, or 72%, during the year ended December 31, 2017 primarily due to production handling agreements fees, commencing in 2017 from certain working interest partners in the Phoenix Field which are recorded as a reduction to lease operating expense.

Lease operating expense. Total lease operating expense for the year ended December 31, 2017 was $121.4 million compared to $139.4 million for the year ended December 31, 2016, a decrease of $18.0 million, or 13%. The decrease was primarily attributed to a $14.3 million decrease in our production facility rental expense as a result of the newly negotiated seven year lease agreement with Helix for use of the HP-I beginning July 2016 which is accounted for as a capital lease (see Note 10 to our consolidated financial statements for the fiscal year ended December 31, 2017 included elsewhere in this prospectus), as well as a $2.4 million decrease in our insurance expense.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the year ended December 31, 2017 was $157.4 million and $124.7 million for the year ended December 31, 2016, an increase of $32.7 million, or 26%. The increase is primarily due to a $1.03 per Boe, or 7%, increase in the

 

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depletion rate on our proved oil and natural gas properties during the year ended December 31, 2017. Depletion on a per Boe basis increased primarily due to inclusion in the full cost pool of the capital lease asset recorded in July 2016 for use of the HP-I. Since the HP-I is utilized in our oil and natural gas development activities, the asset is included within proved property and thus depleted as part of the full cost pool.

General and administrative expense. General and administrative expense for the year ended December 31, 2017 was $36.7 million compared to $28.7 million for the year ended December 31, 2016, an increase of $8.0 million, or 28%. The increase was primarily attributable to $9.7 million in transaction related costs associated with the Stone Combination and our 2017 debt exchange, partially offset by a decrease in employee related expenses of $0.7 million.

Other operating expense. Other operating expense for the year ended December 31, 2017 was $52.1 million compared to $46.6 million for the year ended December 31, 2016, an increase of $5.5 million, or 12%. This increase was primarily related to an increase of $7.8 million in facility and major wellwork due to repairs on South Marsh Island 130. This is partially offset by a decrease of $2.5 million in accretion expense for asset retirement obligations settled in 2017.

Interest expense. Interest expense for the year ended December 31, 2017 was $80.9 million compared to $70.4 million for the year ended December 31, 2016, an increase of $10.5 million, or 15%. The change was primarily due to an increase of $11.5 million from the HP-I capital lease that began in July 2016.

Price risk management activities. Price risk management activities expense for the year ended December 31, 2017 was $27.6 million compared to $57.4 million for the year ended December 31, 2016. The decrease of $29.8 million was attributable to a $178.2 million increase in fair value of our open derivative contracts offset by a $148.2 million decrease in cash settlement gains for the year ended December 31, 2017. These unrealized gains on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss in our consolidated statements of operations at the end of each month. As a result of the derivative contracts we have in place on our anticipated production volumes through 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

 

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Comparison of the Year Ended December 31, 2016 and 2015

The information below provides the financial results and an analysis of significant variances in these results for the year ended December 31, 2016 and 2015 (in thousands):

 

     Year Ended December 31,     Change     % Change  
     2016     2015  

Revenues:

        

Oil revenue

   $ 197,583     $ 244,167     $ (46,584     (19 )% 

Natural gas revenue

     42,705       55,026       (12,321     (22 )% 

NGL revenue

     9,532       10,523       (991     (9 )% 

Other

     8,934       5,890       3,044       52
  

 

 

   

 

 

   

 

 

   

Total revenue

     258,754       315,606       (56,852     (18 )% 

Operating expenses:

        

Direct lease operating expense

     124,360       171,095       (46,735     (27 )% 

Insurance

     13,101       17,965       (4,864     (27 )% 

Production taxes

     1,958       3,311       (1,353     (41 )% 
  

 

 

   

 

 

   

 

 

   

Total lease operating expense

     139,419       192,371       (52,952     (28 )% 

Workover and maintenance expense

     24,810       29,752       (4,942     (17 )% 

Depreciation, depletion and amortization

     124,689       212,689       (88,000     (41 )% 

Write-down of oil and natural gas properties

     —         603,388       (603,388     (100 )% 

Accretion expense

     21,829       19,395       2,434       13

General and administrative expense

     28,686       35,662       (6,976     (20 )% 
  

 

 

   

 

 

   

 

 

   

Total operating expenses

     339,433       1,093,257       (753,824     (69 )% 

Operating loss

     (80,679     (777,651     696,972       90

Interest expense

     (70,415     (51,544     (18,871     (37 )% 

Price risk management activities income (expense)

     (57,398     182,196       (239,594     (132 )% 

Other income

     405       314       91       29
  

 

 

   

 

 

   

 

 

   

Net loss

   $ (208,087   $ (646,685   $ 438,598       68
  

 

 

   

 

 

   

 

 

   

 

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The table below provides additional detail of our production volumes and sales prices per unit.

 

     Year Ended December 31,      Change  
           2016                 2015        

Oil, natural gas, and NGL information:

       

Oil production volume (MBbls)

     5,126       5,161        (35

Oil sales revenue (in thousands)

   $ 197,583     $ 244,167      $ (46,584

Average oil sales price per Bbl (including commodity derivatives)

   $ 68.46     $ 78.42      $ (9.96

Average oil sales price per Bbl (excluding commodity derivatives)

   $ 38.55     $ 47.31      $ (8.76

Average daily NYMEX WTI price per Bbl

   $ 43.32     $ 48.80      $ (5.48

Decrease in oil sales revenue due to:

       

Change in prices (in thousands)

   $ (44,928     

Change in production volume (in thousands)

     (1,656     
  

 

 

      

Total decrease in oil sales revenue (in thousands)

   $ (46,584     
  

 

 

      

Natural gas production volume (MMcf)

     19,001       21,458        (2,457

Natural gas sales revenue (in thousands)

   $ 42,705     $ 55,026      $ (12,321

Average natural gas sales price per Mcf (including commodity derivatives)

   $ 3.24     $ 3.56      $ (0.32

Average natural gas sales price per Mcf (excluding commodity derivatives)

   $ 2.25     $ 2.56      $ (0.31

Average daily NYMEX Henry Hub price per MMBtu

   $ 2.46     $ 2.66      $ (0.20

Decrease in natural gas sales revenue due to:

       

Change in prices (in thousands)

   $ (6,031     

Change in production volume (in thousands)

     (6,290     
  

 

 

      

Total decrease in natural gas sales revenue (in thousands)

   $ (12,321     
  

 

 

      

NGL production volume (MBbls)

     603       588        15  

NGL sales revenue (in thousands)

   $ 9,532     $ 10,523      $ (991

Average NGL sales price per Bbl (excluding commodity derivatives)

   $ 15.81     $ 17.90      $ (2.09

Decrease in NGL sales revenue due to:

       

Change in prices (in thousands)

   $ (1,260     

Change in production volume (in thousands)

     269       
  

 

 

      

Total decrease in NGL sales revenue (in thousands)

   $ (991     
  

 

 

      

Total production per MBoe(1)

     8,896       9,325        (429

Price per Boe(1) (including commodity derivatives)

   $ 47.44     $ 52.72      $ (5.28

Price per Boe(1) (excluding commodity derivatives)

   $ 28.08     $ 33.21      $ (5.13

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

 

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The following table highlights operating expense items in total and on a cost per Boe production basis. The information below provides the financial results and an analysis of significant variances in these results for the years ended December 31, 2016 and 2015 (in thousands, except per Boe data):

 

     Year Ended December 31,  
     2016      2015  
     Total      Per Boe(1)      Total      Per Boe(1)  

Lease operating expenses:

           

Direct lease operating expense

   $ 124,360      $ 13.98      $ 171,095      $ 18.35  

Insurance

     13,101        1.47        17,965        1.93  

Production taxes

     1,958        0.22        3,311        0.36  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total lease operating expenses

     139,419        15.67        192,371        20.64  
  

 

 

    

 

 

    

 

 

    

 

 

 

Depreciation, depletion and amortization

     124,689        14.02        212,689        22.81  

Write-down of oil and natural gas properties

     —          —          603,388        64.70  

General and administrative expense

     28,686        3.22        35,662        3.82  

Other operating expenses:

           

Workover and maintenance expense

     24,810        2.79        29,752        3.19  

Accretion expense

     21,829        2.45        19,395        2.08  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total other operating expenses

     46,639        5.24        49,147        5.27  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total operating expenses

   $ 339,433      $ 38.15      $ 1,093,257      $ 117.24  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Revenue. Total revenue for the year ended December 31, 2016 was $258.8 million compared to $315.6 million for the year ended December 31, 2015, a decrease of $56.9 million, or 18%. Oil revenue decreased by $46.6 million, or 19%, during the year ended December 31, 2016. This decrease was primarily due to a reduction of $8.76 per Bbl in our realized oil sales price.

Natural gas revenue decreased $12.3 million, or 22%, during the year ended December 31, 2016. This decrease was primarily due to a 6.7 MMcf per day decrease in production volumes primarily related to a 3.1 MMcf per day decrease from our Garden Banks 463 Field due to depletion and a 1.9 MMcf per day decrease from our East Cameron 265 Field, a non-operated field which experienced downtime during the year ended December 31, 2016. The decrease in natural gas revenue was also due to a $0.31 per Mcf decrease in our realized average natural gas sales price.

Other revenue increased $3.0 million, or 52%, during the year ended December 31, 2016. This increase was primarily due to process handling agreements with our partners in the Tornado well, GC 281 #1ST (T-9). Initial production of the T-9 well commenced on October 27, 2016.

Lease operating expense. Total lease operating expense for the year ended December 31, 2016 was $139.4 million compared to $192.4 million for the year ended December 31, 2015, a decrease of $53.0 million, or 28%. The decrease primarily related to our continued focus on operational efficiencies and service cost savings to improve operating margins. The decrease was also attributed to a $15.8 million decrease in our production facility rental expense as a result of the newly negotiated seven year lease agreement with Helix for use of the HP-I beginning July 2016. For more information, see Note 10 to our consolidated financial statements for the fiscal year ended December 31, 2017 included elsewhere in this prospectus.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense for the year ended December 31, 2016 was $124.7 million compared to $212.7 million for the year ended December 31,

 

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2015, a decrease of $88.0 million, or 41%. The change is primarily due to a $8.82 per Boe, or 39% decrease, in the depletion rate on our proved oil and natural gas properties during the year ended December 31, 2016. Depletion on a per Boe basis decreased primarily due to the ceiling test write-downs recorded during the third and fourth quarters of 2015 and reserve additions from our Tornado discovery.

Write-down of oil and natural gas properties. Write-down of oil and natural gas properties for the year ended December 31, 2016 was nil compared to $603.4 million for year ended December 31, 2015. During the year ended December 31, 2015, our capitalized oil and natural gas costs exceeded the full cost ceiling calculated as the present value of future net revenues from proved reserves, discounted at 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized, primarily due to lower oil and natural gas prices. See Note 4 to our consolidated financial statements for the fiscal year ended December 31, 2017 included elsewhere in this prospectus.

General and administrative expense. General and administrative expense for the year ended December 31, 2016 was $28.7 million compared to $35.7 million for the year ended December 31, 2015, a decrease of $7.0 million, or 20%. The decrease was primarily attributable to lower legal expenses, which involved a $4.2 million legal expense accrual incurred during the year ended December 31, 2015 (see Note 10 to our consolidated financial statements for the fiscal year ended December 31, 2017 included elsewhere in this prospectus) as well as a decrease of $4.2 million in transaction related costs.

Other operating expense. Other operating expense for the year ended December 31, 2016 was $46.6 million compared to $49.1 million for the year ended December 31, 2015, a decrease of $2.5 million, or 5%. This decrease was primarily related to service cost reductions and reduced workover activity as we focused on the most critical projects.

Interest expense. Interest expense for the year ended December 31, 2016 was $70.4 million compared to $51.5 million for the year ended December 31, 2015, an increase of $18.9 million, or 37%. The change was primarily due to the capital lease treatment of the HP-I agreement to process hydrocarbons produced from the Phoenix Field. As a result of amortization of the capital lease liability under the HP-I agreement, we recorded $13.4 million in additional interest expense during the year ended December 31, 2016. The change was also due to a reduction of capitalized interest of $3.2 million resulting from a decrease in drilling activities and an increase in bonding expense of $2.6 million related to performance bonds posted for the minimum work program in Mexico.

Price risk management activities. Price risk management activities for the year ended December 31, 2016 was an expense of $57.4 million compared to income of $182.2 million for the year ended December 31, 2015. The decrease of $239.6 million was attributable to a $229.8 million decrease in fair value of our open derivative contracts and a $9.8 million decrease in cash settlement gains for the year ended December 31, 2016. These unrealized gains on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss in our consolidated statements of operations at the end of each month. As a result of the derivative contracts we have in place on our anticipated production volumes through 2019, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Note 10 to our audited historical financial statements and Note 11 to our unaudited interim condensed consolidated financial statements, both included elsewhere in this prospectus. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See “Business—Legal Proceedings” for additional information.

 

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Due to the nature of our business, we are, from time to time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operation. See “Business—Legal Proceedings” for additional information.

Supplemental Non-GAAP Measure

Adjusted EBITDA

“Adjusted EBITDA” is not a measure of net income (loss) as determined by GAAP. We use this measure as a supplemental measure because we believe it provides meaningful information to our investors. We define Adjusted EBITDA as net income (loss) plus interest expense, depreciation, depletion and amortization, accretion expense, loss on debt extinguishment, transaction related costs, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), non-cash write-down of oil and natural gas properties, non-cash write-down of other well equipment inventory and non-cash equity based compensation expense. We believe the presentation of Adjusted EBITDA is important to provide management and investors with (i) additional information to evaluate items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

The following tables present a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands, except for Boe data):

 

     Six Months Ended
June 30,
 
     2018      2017  

Reconciliation of net income (loss) to Adjusted EBITDA:

     

Net income (loss)

   $ (97,855    $ 59,069  

Interest expense

     41,420        39,577  

Depreciation, depletion and amortization

     116,766        76,088  

Accretion expense

     14,252        10,509  

Loss on debt extinguishment

     1,408        —    

Transaction related costs

     20,310        4,070  

Derivative fair value (gain) loss(1)

     143,152        (84,888

Net cash receipts (payments) on settled derivative instruments(1)

     (54,056      13,668  

Non-cash equity-based compensation expense

     1,559        495  
  

 

 

    

 

 

 

Adjusted EBITDA

   $ 186,956      $ 118,588  
  

 

 

    

 

 

 

Production:

     

Boe(2)

     6,831        5,222  
  

 

 

    

 

 

 

Other Financial Data:

     

Adjusted EBITDA per Boe(2)

   $ 27.37      $ 22.71  
  

 

 

    

 

 

 

 

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     Year Ended December 31,  
     2017     2016     2015  

Reconciliation of net loss to Adjusted EBITDA:

      

Net loss

   $ (62,868   $ (208,087   $ (646,685

Interest expense

     80,934       70,415       51,544  

Depreciation, depletion and amortization

     157,352       124,689       212,689  

Accretion expense

     19,295       21,829       19,395  

Transaction related costs

     9,652       135       4,291  

Derivative fair value (gain) loss(1)

     27,563       57,398       (182,196

Net cash receipts on settled derivative instruments(1)

     23,834       172,182       181,927  

Non-cash write-down of oil and natural gas properties

     —         —         603,388  

Non-cash write-down of other well equipment inventory

     260       218       2,106  

Non-cash equity-based compensation expense

     875       1,083       1,719  
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 256,897     $ 239,862     $ 248,178  
  

 

 

   

 

 

   

 

 

 

Production:

      

Boe(2)

     10,472       8,896       9,325  
  

 

 

   

 

 

   

 

 

 

Other Financial Data:

      

Adjusted EBITDA per Boe(2)

   $ 24.53     $ 26.96     $ 26.61  
  

 

 

   

 

 

   

 

 

 

 

(1)

The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on a cash basis during the period the derivatives settled.

(2)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated by our operations and borrowings under our newly established Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service and for general corporate purposes. As of June 30, 2018, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $432.9 million.

As of June 30, 2018, total debt, net of discount and deferred financing costs, was approximately $628.4 million, comprised of our $380.0 million aggregate principal amount of the Initial Notes and $6.1 million aggregate principal amount of our 7.50% Stone Senior Notes, $231.5 million outstanding under our Bank Credit Facility, and $10.8 million aggregate principal amount of the Stone 4.20% term loan maturing on November 20, 2030 (the “Building Loan”). We were in compliance with all debt covenants at June 30, 2018. For additional details on our debt, see “Note 6—Debt” to the unaudited interim condensed consolidated financial statements included elsewhere in this prospectus.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2018 capital spending project of $430.0 million to $450.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond

 

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our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, raising debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding debt.

As of June 30, 2018, we had obtained performance bonds primarily related to plugging and abandonment of wells and removal of facilities in the United States Gulf of Mexico and to guarantee the completion of the minimum work program under the Mexico Production Sharing Contracts (“PSCs”) totaling approximately $569.3 million. In July 2016, the BOEM issued the 2016 NTL to clarify the procedures and guidelines the BOEM Regional Directors use to determine if and when additional financial assurances may be required for OCS leases, ROWs and RUEs to meet the BOEM’s estimate of the lessees’ decommissioning obligations. The 2016 NTL became effective in September 2016 and supersedes and replaces NTL #2008-N07. The 2016 NTL allows qualifying operators to self-insure for an amount up to 10% of their tangible net worth. In addition, the 2016 NTL implements a phase-in period for establishing compliance with additional security obligations for certain categories of properties covered under the NTL, whereby a lessee may seek compliance with its additional financial security requirements under a “tailored plan” that is approved by the BOEM and would require securing phased-in compliance in three approximately equal installments during a one-year period from the date of the BOEM’s approval of the tailored plan. However, in June 2017, the BOEM announced that it will extend the implementation timeline for NTL #2016-N01 beyond June 30, 2017, except in certain circumstances where there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities, to allow the BOEM time to reconsider a number of regulatory initiatives. This extension currently remains in effect. We received notice from the BOEM on December 29, 2016 ordering us to secure financial assurances in the form of additional security in the amount of $0.5 million. Subsequent to the December 29, 2016 order, the BOEM has rescinded that order and all others dated December 29, 2016 until further notice. However, the BOEM reserved the right to re-issue sole liability orders in the future, including in the event that it determines there is a substantial risk of nonperformance of the interest holders’ decommissioning sole liabilities. We remain in active discussion with our government regulators and industry peers with regard to any future rule making and financial assurance requirements. Notwithstanding the BOEM’s July 2016 NTL, the BOEM may also increase its financial assurance requirements mandated by rule for all companies operating in federal waters. The future cost of compliance with our existing supplemental bonding requirements, the NTL #2016-N01, as well as any other future directives or any other changes to the BOEM’s rules applicable to us or our subsidiaries’ properties, could materially and adversely affect our financial condition, cash flows and results of operations.

Initial Notes, 7.50% Stone Senior Notes

In connection with the Stone Combination, we consummated the Transactions contemplated by the Exchange Agreement, pursuant to which (i) the Apollo Funds and Riverstone Funds contributed $102.0 million in aggregate principal amount of 9.75% senior notes (“9.75% Senior Notes”) to us in exchange for Common Stock; (ii) the holders of 11.00% Bridge Loans exchanged such 11.00% Bridge Loans for $172.0 million aggregate principal amount of Initial Notes and (iii) Franklin Noteholders and MacKay Noteholders exchanged their 7.50% Stone Senior Notes for $137.4 million aggregate principal amount of Initial Notes. An additional $81.5 million of 7.50% Stone Senior Notes held by non-affiliates were also exchanged for Initial Notes pursuant to an exchange offer and consent solicitation in connection with the Stone Combination.

The exchange of 7.50% Stone Senior Notes for Initial Notes was accounted for as a debt modification. Under a debt modification, a new effective interest rate that equates the revised cash flows to the carrying amount of the Initial Notes is computed and applied prospectively. Costs incurred with third parties directly related to the modification are expensed as incurred. We incurred approximately $3.9 million and $4.5 million of transaction fees related to the exchange of 11.00% Bridge Loans and 7.50% Stone Senior Notes into Initial Notes, which were expensed and reflected in general and administrative expense during the three months and

 

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six months ended June 30, 2018, respectively. We also paid $9.3 million in work fees to debt holders, which are reflected as debt discount reducing long-term debt on the condensed consolidated balance sheet at June 30, 2018.

11.00% Second-Priority Senior Secured Notes—due April 2022. The Initial Notes were issued pursuant to an indenture dated May 10, 2018, between the Talos Issuers, the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The Initial Notes mature April 3, 2022 and have interest payable semi-annually each April 15 and October 15, commencing October 15, 2018. Prior to May 10, 2019, we may, at our option, redeem all or a portion of the Initial Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the Initial Notes at redemption prices decreasing annually from 105.5% to 100.0% plus accrued and unpaid interest.

7.50% Senior Secured Notes—due May 2022. The 7.50% Stone Senior Notes represent the remaining $6.1 million of long-term debt assumed in the Stone Combination that were not exchanged for Initial Notes pursuant to the exchange offer and consent solicitation, and thus remain outstanding. As a result of the exchange offer and consent solicitation, substantially all of the restrictive covenants relating to the 7.50% Stone Senior Notes have been removed and collateral securing the 7.50% Stone Senior Notes have been released. The 7.50% Stone Senior Notes mature May 31, 2022 and have interest payable semiannually each May 31 and November 30. Prior to May 31, 2020, we may, at our option, redeem all or a portion of the 7.50% Stone Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 7.50% Stone Senior Notes at redemption prices decreasing annually from 105.625% to 100.0% plus accrued and unpaid interest.

Bank Credit Facility

We executed the Bank Credit Facility in conjunction with the Stone Combination with a syndicate of financial institutions, with an initial borrowing base of $600.0 million. The Bank Credit Facility matures on May 10, 2022.

The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter. In June 2018, we completed the redetermination and the borrowing base was reaffirmed at $600.0 million. The next redetermination is in October 2018.

As of June 30, 2018, our borrowing base was set at $600.0 million, of which no more than $200 million can be used as letters of credit. The amount that we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. We were in compliance with all debt covenants at June 30, 2018. As of June 30, 2018, the Bank Credit Facility had approximately $354.0 million of undrawn commitments (taking into account $6.0 million letters of credit and $240.0 million drawn from the Bank Credit Facility). The $294.0 million in cash received from our initial drawdown under the Bank Credit Facility was used to partially repay outstanding borrowings under our previous credit facility upon its termination in connection with the Stone Combination.

Building Loan

In connection with the Stone Combination, we assumed Stone’s Building Loan maturing on November 20, 2030. The Building Loan bears interest at a rate of 4.20% per annum and is to be repaid in 180 equal monthly installments of approximately $0.1 million. As of June 30, 2018, the outstanding balance under the Building Loan totaled $10.8 million. The Building Loan is collateralized by our two Lafayette, Louisiana office buildings. Under the financial covenants of the Building Loan, we must maintain a ratio of EBITDA to Net Interest Expense of not less than 2.00 to 1.00. In addition, the Building Loan contains certain customary restrictions or requirements with respect to change of control and reporting responsibilities. We are in compliance with all covenants under the Building Loan as of June 30, 2018.

 

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2018 Senior Notes

9.75% Senior Notes—due February 2018. The 9.75% Senior Notes were issued pursuant to an indenture dated February 6, 2013 among the Talos Issuers, the subsidiary guarantors party thereto and the trustee. On February 15, 2018, the Talos Issuers redeemed the remaining $25.0 million principal amount of the 9.75% Senior Notes at par.

Overview of Cash Flow Activities

The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

 

     Six Months Ended
June 30,
 
     2018      2017  

Operating Activities

   $ 107,111      $ 85,263  

Investing Activities

   $ 152,033      $ (64,779

Financing Activities

   $ (212,473    $ (11,870

Operating Activities. Net cash provided by operating activities increased $21.8 million in the six months ended June 30, 2018 from 2017 primarily attributable to an increase in revenue, partially offset by a decrease in cash settlements on derivatives instruments and transaction related costs related to the Stone Combination.

Investing Activities. Net cash provided by investing activities increased $216.8 million in the six months ended June 30, 2018 from 2017 primarily attributable to $293.0 million cash acquired for the Stone Combination, partially offset by a $78.4 million increase in capital expenditures.

Financing Activities. Net cash used in financing activities increased $200.6 million in the six months ended June 30, 2018 from 2017 primarily attributable to the repayment of $403.0 million related to our previous credit facility, $54.0 million related to the repayment of the Bank Credit Facility, $25.0 million related to the redemption of our 2018 Senior Notes and $17.5 million in deferred financing cost, partially offset by proceeds received from the Bank Credit Facility of $294.0 million.

Capital Expenditures. We fund exploration and development activities primarily through operating cash flows, cash on hand and through borrowings under our Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions through the issuance of senior notes, borrowings under the bank credit facility and through additional equity transactions. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

For the six months ended June 30, 2018, our additions to property and equipment, excluding acquisitions, plugging and abandonment spend and asset retirement costs, on an accrual basis were $88.3 million, an increase of $9.3 million, or 12%, from the six months ended June 30, 2017. Our additions for the six months ended June 30, 2018 were as follows (in thousands):

 

Exploration

   $ 13,462  

Development

     60,333  

Geological and geophysical/seismic

     2,928  

Land and lease

     2,388  

Other

     9,163  
  

 

 

 

Total

   $ 88,274  
  

 

 

 

 

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Additionally, we incurred $43.9 million on plugging and abandonment and $46.8 for the change in control related to seismic during the six months ended June 30, 2018.

Capital expenditures for the remainder of 2018 are estimated to be approximately $240.0 million to $260.0 million, which we plan to fund through cash flows from operations and borrowings under our Bank Credit Facility.

The following table summarizes cash flows provided by (used in) type of activity, for the following periods (in thousands):

 

     Year Ended December 31,  
     2017      2016      2015  

Operating Activities

   $ 176,053      $ 116,123      $ 138,366  

Investing Activities

   $ (157,641    $ (198,918    $ (285,139

Financing Activities

   $ (18,412    $ 91,624      $ 108,231  

Operating Activities. Net cash provided by operating activities increased $59.9 million in 2017 from 2016 primarily attributable to an increase in revenue, offset by a decrease in cash settlements on our derivative contracts. Net cash provided by operating activities decreased $22.2 million from 2015 to 2016 primarily due to a decrease in revenue and decrease in cash settlements on our derivative contracts.

Investing Activities. Net cash used in investing activities decreased $41.3 million in 2017 from 2016 as a result of decreased capital expenditures. The decrease of $86.2 million in net cash used in investing activities from 2015 to 2016 primarily related to decreased capital expenditure and acquisition spending in response to the depressed commodity environment.

Financing Activities. The change of $110.0 million in net cash used in financing activities in 2017 compared to net cash provided by financing activities in 2016 was primarily due to a reduction of $91.9 million net contribution from the Sponsors. Net cash provided by financing activities decreased $16.6 million in 2016 from 2015 primarily related to a decrease of $85.0 million in net proceeds drawn from the Bank Credit Facility, $55.0 million repayment of GCER’s senior reserve-based revolving credit facility in 2015, offset by an increase of $18.4 million net contributions from the Sponsors in 2016 from 2015.

Capital Expenditures. We fund exploration and development activities primarily through operating cash flows, cash on hand, and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant property acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities.

For the year ended December 31, 2017, our additions to property and equipment, excluding acquisitions, plugging and abandonment spend and asset retirement costs, on an accrual basis were $194.5 million, an increase of $73.1 million, or 60%, from the year ended December 31, 2016. Our additions for the year ended December 31, 2017 were as follows (in thousands):

 

Exploration

   $ 77,243  

Development(1)

     106,899  

Geological and geophysical/seismic

     5,644  

Land and lease

     4,422  

Other

     327  
  

 

 

 

Total

   $ 194,535  
  

 

 

 

 

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(1)

Includes $11.7 million of subsea inventory paid for in 2016, which was transferred to development projects in 2017.

Additionally we incurred $32.7 million on plugging and abandonment during the year ended December 31, 2017.

Off Balance Sheet Arrangements

We did not have any off balance sheet arrangements as of June 30, 2018.

Contractual Obligations

We are party to various contractual obligations. Some of these obligations may be reflected in our accompanying consolidated financial statements, while other obligations, such as operating leases and capital commitments, are not reflected on our accompanying consolidated financial statements.

The following table and discussion summarizes our contractual cash obligations as of June 30, 2018 (in thousands):

 

     2018      2019      2020      2021      Thereafter      Total  

Long-term financing obligations:

                 

Debt principal

   $ —        $ —        $ —        $ —        $ 636,928      $ 636,928  

Debt interest

     28,796        57,592        57,592        57,592        15,677        217,249  

Vessel commitments(1)

     22,030        11,765        —          —          —          33,795  

Building Loan

     439        878        878        878        7,706        10,779  

Derivative liabilities

     92,293        94,195        —          —          —          186,488  

Committed purchase orders(2)

     1,460        13,704        —          —          —          15,164  

Capital lease(3)

     22,500        45,000        45,000        45,000        63,750        221,250  

Minimum lease payments

     662        153        1,421        3,611        30,878        36,725  

Mexico minimum work program

     —          34,942        —          —          —          34,942  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations(4)

   $ 168,180      $ 258,229      $ 104,891      $ 107,081      $ 754,939      $ 1,393,320  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1)

Includes commitments for drilling rigs and Helix’s Q4000 well intervention vessel we will utilize for certain deep water well intervention and decommissioning activities.

(2)

Includes committed purchase orders to execute planned future drilling and completion activities.

(3)

Lease agreement for the HP-I floating production facility in the Phoenix Field.

(4)

This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $414.4 million as of June 30, 2018. For additional information regarding these liabilities, please see Note 4—Property, Plant and Equipment to our unaudited interim condensed consolidated financial statements included elsewhere in this prospectus.

Performance Bonds. As of June 30, 2018 and December 31, 2017, we had secured performance bonds primarily related to plugging and abandonment of wells and removal of facilities and executing the minimum work program in Mexico totaling approximately $569.3 million and $287.8 million, respectively. As of June 30, 2018 and December 31, 2017, we had $6.0 million and $4.9 million, respectively, in letters of credit issued under our Bank Credit Facility and our previous credit facility.

For additional information about certain of our obligations and contingencies, see “Note 11—Commitments and Contingencies” to the unaudited interim condensed consolidated financial statements included elsewhere in this prospectus.

 

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Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production. All derivatives are recorded on the condensed consolidated balance sheet at fair value with settlements of such contracts and, changes in the unrealized fair value recorded as price risk management activities income (expense) on the condensed consolidated statements of operations in each period.

Commodity Price Risks

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During the six months ended June 30, 2018, our average oil price realizations after the effect of derivatives increased 6% to $54.12 per Bbl from $51.28 per Bbl in the comparable 2017 period. Our average natural gas prices realizations after the effect of derivatives increased 2% during the six months ended June 30, 2018 to $2.94 per Mcf from $2.87 per Mcf in the comparable 2017 period.

Price Risk Management Activities

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

We had commodity derivative instruments in place to reduce the price risk associated with future production of 14,444 MBbls of crude oil and 9,177 MMBtu of natural gas at June 30, 2018, with a net derivative liability position of $185.8 million. For additional information regarding our commodity derivative instruments, see “Note 5—Financial Instruments” to our consolidated financial statements for the fiscal year ended December 31, 2017 and “Note 5—Financial Instruments” to our unaudited interim condensed consolidated financial statements, both included elsewhere in this prospectus. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at June 30, 2018 (in thousands):

 

           Oil and Natural Gas Derivatives  
           10 Percent Increase     10 Percent Decrease  
     Fair Value     Fair Value     Change     Fair Value     Change  

Price impact(1)

   $ (185,755   $ (281,258   $ (95,503   $ (90,224   $ 95,531  

 

(1)

Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

Variable Interest Rate Risks

We had total debt outstanding of $628.4 million at June 30, 2018, net of unamortized original issue discount and deferred financing costs. Of this, $396.9 million was from our Initial Notes, 7.50% Stone Senior Notes and Building Loan, which bear interest at fixed rates. The remaining $231.5 million is from borrowings under our Bank Credit Facility with variable interest rates. Therefore, we are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. We believe our interest rate risk exposure is partially mitigated as a result of fixed interest rates on 63% of our debt. The interest rate on our variable rate debt at June 30, 2018 was 5.05%. A 10% change in the interest

 

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rate on this variable rate debt balance at June 30, 2018 would change interest expense for the six months ended June 30, 2018 by approximately $0.3 million.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies that have been implemented or changed since December 31, 2017 are described in “Note 2—Summary of Significant Accounting Policies” of our unaudited interim condensed consolidated financial statements included elsewhere in this prospectus. Our other significant accounting policies that are not referenced in Note 2 can be found within our audited financial statements and the notes thereto for the year ended December 31, 2017 included elsewhere in this prospectus.

Oil and Natural Gas Properties

We follow the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country by country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, wells currently drilling and capitalized interest are initially excluded from the amortizable base. We transfer unproved property costs into the amortizable base when properties are determined to have proved reserves or when we have completed an evaluation of the unproved properties resulting in an impairment. We evaluate each of these unproved properties individually for impairment at least quarterly. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which we own a direct interest.

Our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, discounted at 10 %, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized. Any costs in excess of the ceiling are recognized as a non-cash impairment expense on our consolidated statement of operations and an increase to accumulated depreciation, depletion and amortization on our consolidated balance sheet. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. We perform this ceiling test calculation each quarter. In accordance with SEC rules and regulations, we utilize SEC Pricing when performing the ceiling test. We also hold prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period. The ceiling test computation did not result in a write-down of our oil and natural gas properties during the three and six months ended June 30, 2018 and 2017.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not

 

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qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When we sell or convey interests in oil and natural gas properties, we reduce our oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves. We treat sales proceeds on non-significant sales as reductions to the cost of our oil and natural gas properties.

We recognize transportation costs as a component of direct lease operating expense when we are the shipper of the product. Such costs during the three and six months ended June 30, 2018 were $5.8 million and $2.7 million, respectively, and $5.0 million and $2.7 million during the three and six months ended June 30, 2017, respectively.

Proved Reserve Estimates

We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC Pricing.

Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

Fair Value Measure of Financial Instruments

Our financial instruments generally consisted of cash and cash equivalents, restricted cash, accounts receivable, commodity derivatives, accounts payable and debt as of June 30, 2018. The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value as an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. We follow a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

Level 1—Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2—Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

 

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Level 3—Inputs to the valuation methodology are unobservable (little or no market data), which require us to develop our own assumptions, and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

Market Approach—Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

Cost Approach—Amount that would be required to replace the service capacity of an asset (replacement cost).

Income Approach—Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Asset Retirement Obligations

We are required to record our asset retirement obligations at fair value in the period such obligations are incurred with the associated asset retirement costs being capitalized as part of the carrying cost of the asset. Our asset retirement obligations consist of estimated costs for dismantlement, removal, site reclamation and similar activities associated with our oil and natural gas properties. The estimate of the asset retirement cost is determined, inflated to an estimated future value using a three year average of the Consumer Price Index and discounted to present value using our credit-adjusted risk-free rate. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

Revenue Recognition and Imbalances

We record revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred.

We have interests with other producers in certain properties. In these cases, we use the entitlement method to account for sales of production. Under the entitlement method, revenue is recorded when title passes based on our net interest. We may receive more or less than our entitled share of production, and we record our entitled share of revenues based on entitled volumes and contracted sales prices. If we receive more than our entitled share of production, the imbalance is recorded as a liability in accrued liabilities on the consolidated balance sheets. If we receive less than our entitled share, the imbalance is recorded as an asset in other current assets on the consolidated balance sheets. Our imbalances are recorded gross on our consolidated balance sheets. At June 30, 2018, our imbalance receivable was approximately $1.7 million and imbalance payable was approximately $2.5 million. At December 31, 2017, our imbalance receivable was approximately $2.1 million and imbalance payable was approximately $2.7 million.

We record the gross amount of reimbursements for costs from third parties as other revenues whenever we are the primary obligor with respect to the source of such costs, have discretion in the selection of how the

 

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related costs are incurred and when we have assumed the credit risk associated with the reimbursement for such costs. The costs associated with these third-party reimbursements are also recorded within the applicable cost and expenses line item in the consolidated statements of operations. Our other revenues have been generated primarily through fees for processing third-party production through some of our production facilities.

Income Taxes

Our provision for income taxes includes both state, federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of June 30, 2018, we believe it is more likely than not that the net deferred tax asset will not be realized and therefore have recorded a valuation allowance.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Recently Adopted Accounting Standards

See “Note 1—Formation and Basis of Presentation” to the unaudited interim condensed consolidated financial statements included elsewhere in this prospectus for our Recently Adopted Accounting Standards.

Recently Issued Accounting Standards

See “Note 1—Formation and Basis of Presentation” to the unaudited interim condensed consolidated financial statements included elsewhere in this prospectus for Recently Issued Accounting Standards applicable to us.

 

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BUSINESS

Our Company

We are a technically driven independent exploration and production company with operations in the United States Gulf of Mexico and in the shallow waters off the coast of Mexico. Our focus in the Gulf of Mexico is the exploration, acquisition, exploitation and development of deep and shallow water assets near existing infrastructure. The shallow waters off the coast of Mexico provide us high impact exploration opportunities in an emerging basin. We use our access to an extensive seismic database and our deep technical expertise to identify, acquire and exploit attractive assets with robust economic profiles. Our management and technical teams have a long history working together and have made significant discoveries in the deep and shallow waters in the Gulf of Mexico and in the shallow waters off the coast of Mexico.

We have historically focused our operations in the Gulf of Mexico because we believe those areas provide us with favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic databases, extensive infrastructure, and an attractive acquisition market and because we have significant experience and technical expertise in the basin. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate acquisition and joint venture opportunities, which we believe provides significant upside.

In September 2015, the Consortium executed two PSCs with Mexico’s upstream regulator, the National Hydrocarbons Commission, for Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively. Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays.

In order to determine the most attractive returns for our drilling program, we employ a disciplined portfolio management approach to stochastically evaluate all of our drilling prospects, whether they are generated organically from our existing acreage or are acquisition or joint venture opportunities. We add to and reevaluate our inventory in order to deploy capital as efficiently as possible.

We plan to opportunistically expand our asset base by evaluating the robust supply of acquisition opportunities in the Gulf of Mexico. The acquisition strategy is focused on deep and shallow water assets with a geological setting that can benefit from our access to an extensive seismic database and reprocessing expertise to re-evaluate the acquired assets. We expect to target acquisitions involving assets with physical infrastructure that will allow us to focus on additional drilling opportunities. By applying a disciplined valuation methodology, we seek to reduce the risk of underperformance of the acquired properties while maintaining the potential for higher returns on our investment. In addition, we may consider acquisition opportunities in other offshore basins with analogous geologies that are suitable for our operational and technical expertise to the extent we believe it will increase our reserves and enhance returns on our investment and long-term growth prospects.

As of December 31, 2017, our estimated proved reserves were 100.6 million barrels of oil equivalent (“MMBoe”), of which approximately 72% was oil and 53% was proved developed. Approximately 74% of our proved reserves are located in the deepwater and 26% are located on the shelf, which we believe provides us with a balanced portfolio of lower risk development opportunities and high impact development upside. Our estimated proved reserves have a standardized measure and a PV-10 of approximately $1.8 billion (of which approximately $1.0 billion is attributable to proved developed reserves).

 

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During 2017, we spent $227.2 million on capital expenditures, which included $32.7 million on plugging and abandonment activities. Our full year 2018 capital expenditure budget, inclusive of Stone, is approximately $430 million to $450 million, excluding amounts paid for acquisitions and plugging and abandonment. We expect to spend $112 million to $117 million on plugging and abandonment activities in 2018.

Properties

The following table provides a summary of selected operating information for our properties as of December 31, 2017:

 

     Estimated Proved Reserves(1)        

Operating Area

   MBoe(2)      % Oil     % Natural
Gas
    % NGLs     % Proved
Developed
    2017 Net
Production
(MBoe)(2)
 

Deepwater:

             

Operated

     73,447        79     13     8     47     6,043  

Non-Operated

     620        62     38     —       100     663  
  

 

 

            

 

 

 

Deepwater Subtotal

     74,067        79     13     8     48     6,706  

Shelf:

             

Operated

     24,338        54     43     3     68     3,000  

Non-Operated

     2,220        40     50     10     92     766  
  

 

 

            

 

 

 

Shelf Subtotal

     26,558        54     43     3     70     3,766  
  

 

 

            

 

 

 

Total United States

     100,625        72     21     7     53     10,472  
  

 

 

            

 

 

 

 

(1)

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2017 were determined to be economically producible under existing economic conditions, which require the use of SEC pricing (as defined in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-9905; 34-59192)). For oil, the NYMEX WTI posted price was used in the calculation and the adjusted price of $51.36 per Bbl over life was used in computing the proved reserve amounts above at December 31, 2017. For natural gas, the average NYMEX Henry Hub spot price was used in the calculation and the adjusted price of $3.20 per Mcf over life was used in computing the proved reserve amounts above at December 31, 2017. For NGLs, a ratio was computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio was applied to the oil price using SEC guidance. The NGLs price of $24.64 per Bbl over life was used in computing the proved reserve amounts above at December 31, 2017. Such prices were held constant throughout the estimated lives of the reserves. Future production, development costs and asset retirement obligations are based on year-end costs with no escalations.

(2)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

United States

In the United States, at December 31, 2017, we operated or had an interest in 159.0 gross (122.5 net) producing wells on 467,858 gross (378,560 net) total acres of which 302,513 gross (219,553 net) are developed acres, including interests in 158 producing leases. We operate properties that contain 97% of our proved reserves at December 31, 2017. Our current areas of focus include:

 

   

the Gulf of Mexico deepwater area, which is generally considered to comprise water depths of more than 600 feet. Our strategy is focused in areas characterized by clearly defined infrastructure, well known production history and geological well control, which reduces operational and investment risk. We believe the potential for large discoveries and increasing success rates in the sub-salt and mini-basin lower Pliocene and Miocene plays have resulted in increased industry focus on this area over the last decade; and

 

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the Gulf of Mexico shelf, which is characterized primarily by water depths of up to 600 feet in both state and federal water. This area is a mature petroleum province with lower risk exploration opportunities and easy access to asset management opportunities with attractive incremental returns. Plio-Pleistocene and Miocene geological plays on the shelf have been the focus of the industry for several decades because they contain high quality oil and natural gas producing assets with stacked pay sands and are close to developed infrastructure.

 

 

LOGO

At December 31, 2017, our core properties in the United States, which represent approximately 69% of our 2017 production and 78% of our proved reserves, included the following:

 

   

Phoenix Field—We operate and have a 100% working interest in the Phoenix Field, comprised of Green Canyon Blocks 236, 237, 238, 280 and 282, except the Tornado I and Tornado II wells, which we operate and have a 65% working interest.

The Phoenix Field is located offshore Louisiana in about 2,000 feet of water. The field was originally discovered in 1998 by Chevron U.S.A. Production Co. The Phoenix Field’s cumulative production is 90.2 MMBoe from reservoirs ranging from 13,600 – 20,400 feet in depth. There are no conventional fixed or moored production platforms in the field – instead the subsea wells are tied back to a dynamically positioned floating production unit, the HP-I. The HP-I interconnects with the Phoenix Field through a production buoy that can be disconnected if the HP-I cannot maintain its position on station, such as in the event of a mechanical problem with the dynamic positioning system or the approach of a hurricane. There are eight active wells and three shut-in wells located in the field.

We continue to focus our exploration and development activities in the Phoenix Field as evidenced by the successful drilling of our Tornado II project in 2017. In October 2017, we completed the Tornado II deepwater drilling program in the Phoenix Field of the Gulf of Mexico in approximately 2,700 feet of water. The Tornado II drilling program consisted of an exploratory test penetration in an adjacent fault block to our initial Tornado discovery in 2016, followed by a sidetrack well to delineate the initial

 

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reservoir. The test penetration was drilled to a total vertical depth of approximately 21,107 feet and logged approximately 222 feet measured depth (176 feet total vertical depth) of net oil pay across the B-5 and B-6 sands. The discovered resource which is presented as proved undeveloped reserves at December 31, 2017 increases our existing drilling inventory and is scheduled in the 2018 drilling program, subject to the working interest partner’s approval. The sidetrack delineation well, known as the GC 281 #2ST well, was drilled to a total vertical depth of approximately 21,057 feet and logged approximately 297 feet total measured depth (282 feet total vertical depth) of net oil pay across the B-5 and B-6 sands. Initial production from the GC 281 #2ST commenced in late December 2017 and is tied into the existing Phoenix Field subsea infrastructure and flows to the HP-1. To execute the Tornado II drilling program, we contracted the Ensco 8503, a dynamically positioned floating drilling rig.

The field’s net daily production for the year ended December 31, 2017 was 16,559 Boepd. Estimated net proved reserves for the field at December 31, 2017 were 72,388 MBoe (79% oil, 13% natural gas and 8% NGLs).

 

   

Ewing Bank 305 Field—We operate and have a 100% working interest in the Ewing Bank 305 Field, comprised of Ewing Bank Blocks 305 and 306 and Mississippi Canyon Block 265. The field is located offshore Louisiana in approximately 275 feet of water. The field was originally discovered by Conoco Oil Company in 1980 and commenced production in 1986. Reservoir depths range from 6,500 to 11,300 feet. There is one production platform, 11 active wells and five shut-in wells located throughout the field. Through our asset management program, we increased production in 2017 by approximately 400 Boepd net on average compared with 2016. We performed three successful recompletions, two workovers and gas-lift optimization throughout the field during 2017 resulting in net daily production during December 2017 of approximately 2,200 Boepd. The field’s net daily production for the year ended December 31, 2017 was 1,632 Boepd. Estimated net proved reserves for the field at December 31, 2017 were 2,746 MBoe (44% oil, 51% natural gas and 5% NGLs).

 

   

South Pelto 22 Field—We operate and have a 100% working interest in the South Pelto 22 Field, comprised of South Pelto Blocks 22 and 23, and South Timbalier Block 75 which are located offshore Louisiana in approximately 60 feet of water. The field was originally discovered by the California Company in 1962 and commenced production in 1963. Reservoir depths range from approximately 5,000 to 18,000 feet. There are nine platforms, six active wells and six shut-in wells located throughout the field. The 2017 South Pelto 22 Field program, which included two successful recompletions and one well drilled and completed resulted in a net daily production increase of 224 Boepd from 2016. The field’s net daily production for the year ended December 31, 2017 was 779 Boepd. Estimated net proved reserves for the field at December 31, 2017 were 1,990 MBoe (37% oil, 56% natural gas and 7% NGLs).

 

   

Ship Shoal 111 Field—We operate and have a 100% working interest in the Ship Shoal 111 Field, comprised of three platforms in Ship Shoal Block 111 located in offshore Louisiana state waters in approximately 30 feet of water. The field was originally discovered by Exxon Mobil Corporation in 1985 and then redeveloped by Bois d’ Arc in 2004. Production ranges in depth from 10,200 to 14,600 feet. There are three production platforms, four active wells and two shut-in wells located throughout the field. The 2017 asset management plan included one recompletion which was successfully completed. The field’s net daily production for the year ended December 31, 2017 was 749 Boepd. Estimated net proved reserves for the field at December 31, 2017 were 938 MBoe (3% oil, 86% natural gas and 11% NGLs).

Mexico

On September 4, 2015, the Consortium executed two PSCs with Mexico’s upstream regulator, the CNH, for Blocks 2 and 7 of Round 1. The PSCs were awarded to the Consortium during the first tender of Mexico’s oil and natural gas fields in over 80 years. Blocks 2 and 7 are located in the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Veracruz and Tabasco states, respectively.

 

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Blocks 2 and 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays. We will continue to assess other exploration potential opportunities off the coast of Mexico.

In July 2017, we completed drilling operations on the offshore Mexico Zama-1 exploration well in Block 7, reaching a total depth of 13,480 feet. The Zama-1 well is the first offshore exploration well to be drilled in Mexico by the private sector. Well results confirmed the base of the reservoir section, with no penetration of an oil-water contact. The well was also drilled deeper into a higher risk formation, but no additional commercial quantities of hydrocarbons were encountered. The gross oil bearing interval is over 1,100 feet with petrophysical data indicating excellent rock properties and an oil sample with 30 degree American Petroleum Institute (“API”) gravity oil. The well has been suspended as a future producer. We are now analyzing all the data gathered from the Zama-1 well and evaluating the optimal methods for appraisal and development of the discovery. These contingent resources are not included in proved or probable reserves.

We are the operator and currently have a 45% and 35% participation interest in Block 2 and Block 7, respectively, with Sierra and Premier holding the remainder and sharing in the exploration, development and production costs. Premier has an option to increase or decrease its participation interest in Block 2, which could adjust our participation interest for that block to between 35% and 45%. Premier previously exercised an option to increase its participation interest in Block 7, which decreased our participation interest for that block from 45% to 35%. The PSCs include a cost recovery feature pursuant to which eligible costs in relation to the minimum work program activities are recoverable in-kind at a rate of 125% of costs from future production volumes. Production volumes are allocated in-kind between the Consortium and the United Mexican States on a monthly basis based on the contractual value of the hydrocarbons as defined in the PSCs. Up to 60% of the monthly contractual value of the hydrocarbons will be allocated to the Consortium to recover eligible costs incurred in petroleum activities. Eligible costs exceeding 60% of the current month contractual value of the hydrocarbons will be recoverable in future periods. Between 7.5% and 14% of the contractual value of the oil will be allocated to the United Mexican States in the form of a royalty, depending upon the price of a barrel of oil, with a collar between $48.00 and $100.00 per Bbl. The allocation for the royalty on natural gas is 0% when the price per MMBtu is below $5.00 and, if the natural gas price exceeds $5.00 per MMBtu, the royalty allocation percentage is calculated as the price per MMBtu divided by 100. The remaining value of the hydrocarbons after the allocation for cost recovery and royalties is considered operating profit under the PSCs. The allocation of operating profit to the Consortium after the allocation for cost recovery and royalties on Blocks 2 and 7 is 44% and 31%, respectively. Additionally, in the event that the cumulative project internal rate of return in any one month exceeds 25%, the barrels of oil allocated to the Consortium after cost recovery

 

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(“Profit Oil”) is reduced on a sliding scale. The reduction in Profit Oil varies linearly between 0% and 75% of the entitled amount. The maximum 75% reduction occurs once the cumulative project internal rate of return meets or exceeds 40%.

 

LOGO

 

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Summary of Reserves

Our estimated proved reserves totaled 100.6 MMBoe at December 31, 2017. The following table summarizes our estimated proved and probable reserves as of December 31, 2017 and 2016, and our proved reserves as of December 31, 2015, on a historical basis:

 

    Summary of Reserves  
    Oil
(MBbls)
    Natural
Gas
(MMcf)
    NGL
(MBbls)
    MBoe(2)     Percent of
Total
    PV-10
(in thousands)(3)
    Standardized
Measure
(in thousands)(4)
 

December 31, 2017(1)

             

Proved Developed Producing

    23,656       37,161       1,930       31,780       $ 776,786     $ 776,786  

Proved Developed Non-Producing

    13,804       40,416       1,385       21,924         270,363       270,363  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved Developed

    37,460       77,577       3,315       53,704       53     1,047,149       1,047,149  

Proved Undeveloped

    35,344       50,079       3,232       46,921       47     760,520       760,520  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved

    72,804       127,656       6,547       100,625       $ 1,807,669     $ 1,807,669  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Probable Developed Producing(5)

    8,370       11,595       721       11,023        

Probable Developed Non-Producing(5)

    738       9,687       136       2,489        
 

 

 

   

 

 

   

 

 

   

 

 

       

Total Probable Developed(5)

    9,108       21,282       857       13,512       50    

Probable Undeveloped(5)

    9,361       19,299       865       13,442       50    
 

 

 

   

 

 

   

 

 

   

 

 

       

Total Probable(5)

    18,469       40,581       1,722       26,954        
 

 

 

   

 

 

   

 

 

   

 

 

       

December 31, 2016(1)

             

Proved Developed Producing

    28,757       52,062       2,277       39,711       $ 707,315     $ 707,315  

Proved Developed Non-Producing

    16,996       44,060       1,754       26,094         242,877       242,877  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved Developed

    45,753       96,122       4,031       65,805       63     950,192       950,192  

Proved Undeveloped

    26,613       54,482       2,205       37,897       37     385,843       385,843  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved

    72,366       150,604       6,236       103,702       $ 1,366,035     $ 1,366,035  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Probable Developed Producing(5)

    5,369       13,314       518       8,105        

Probable Developed Non-Producing(5)

    3,453       9,694       388       5,457        
 

 

 

   

 

 

   

 

 

   

 

 

       

Total Probable Developed(5)

    8,822       23,008       906       13,562       38    

Probable Undeveloped(5)

    16,413       24,245       1,316       21,770       62    
 

 

 

   

 

 

   

 

 

   

 

 

       

Total Probable(5)

    25,235       47,253       2,222       35,332        
 

 

 

   

 

 

   

 

 

   

 

 

       

December 31, 2015(1)

             

Proved Developed Producing

    23,462       49,775       2,184       33,942       $ 468,552     $ 468,552  

Proved Developed Non-Producing

    9,554       40,657       1,199       17,529         70,638       70,638  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved Developed

    33,016       90,432       3,383       51,471       71     539,190       539,190  

Proved Undeveloped

    13,338       38,792       1,198       21,002       29     63,791       63,791  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

Total Proved

    46,354       129,224       4,581       72,473       $ 602,981     $ 602,981  
 

 

 

   

 

 

   

 

 

   

 

 

     

 

 

   

 

 

 

 

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(1)

In accordance with guidelines established by the SEC, our estimated proved reserves as of December 31, 2017, 2016 and 2015 were determined to be economically producible under existing economic conditions, which require the use of SEC pricing. For oil, the NYMEX WTI posted price was used in the calculation and the adjusted price of $51.36, $40.02 and $50.72 per Bbl over life was used in computing the proved reserve amounts above at December 31, 2017, 2016 and 2015, respectively. For natural gas, the average NYMEX Henry Hub spot price was used in the calculation and the adjusted price of $3.20, $2.66 and $2.75 per Mcf over life was used in computing the proved reserve amounts above at December 31, 2017, 2016 and 2015, respectively. For NGLs, a ratio was computed for each field of the NGLs realized price compared to the oil realized price. Then, this ratio was applied to the oil price using SEC guidance. The NGLs price of $24.64, $14.96 and $17.60 per Bbl over life was used in computing the proved reserve amounts above at December 31, 2017, 2016 and 2015, respectively. Such prices were held constant throughout the estimated lives of the reserves. Future production, development costs and asset retirement obligations are based on year-end costs with no escalations.

(2)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

(3)

PV-10 was prepared using SEC pricing discounted at 10% per annum, without giving effect to federal income taxes or derivatives. PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after tax amount, because it presents the discounted future net cash flows attributable to our reserves prior to taking into account future corporate income taxes and our current tax structure. PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. PV-10 does not take into account the effect of future taxes. PV-10 estimates for price sensitivities are not adjusted for the likelihood that the relevant pricing scenario will occur. Investors should be cautioned that neither PV-10 nor standardized measure represent an estimate of the fair market value of our proved reserves.

(4)

Standardized measure represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and abandonment costs, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Standardized measure is based on proved reserves as of fiscal year end calculated using unweighted arithmetic average first-day-of-the-month prices for the prior 12 months. Our standardized measure does not include the impact of future federal income taxes because we were not subject to federal income taxes prior to the Stone Combination and standardized measure is therefore equal to PV-10.

(5)

Estimates of probable reserves are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty. Therefore, these reserve categories are not comparable and have not been, and should not be, summed arithmetically.

Changes in Proved Developed Reserves

Our proved developed reserves as of December 31, 2017 decreased by 12.1 MMBoe to 53.7 MMBoe from 65.8 MMBoe at December 31, 2016, an 18% decrease. This decrease was due to:

 

   

production of 10.5 MMBoe; and

 

   

downward revisions of 4.5 MMBoe primarily due to the reclassification of the Motormouth well in the Phoenix Field to PUD reserves as a result of a mechanical failure requiring a new wellbore; offset by,

 

   

extensions and discoveries of 2.9 MMBoe primarily from the Tornado II well.

 

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Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities during the year ended December 31, 2017.

 

     Oil, Natural
Gas and
NGLs
     Future
Development
Costs
 
     (MBoe)(1)      (In thousands)  

Proved undeveloped reserves at December 31, 2016

     37,897      $ 304,488  

Extensions and discoveries

     9,576        77,236  

Revisions of previous estimates

     (552      65,997  
  

 

 

    

 

 

 

Total proved undeveloped reserves changes

     9,024        143,233  
  

 

 

    

 

 

 

Proved undeveloped reserves at December 31, 2017

     46,921      $ 447,721  
  

 

 

    

 

 

 

 

(1)

One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Our PUD reserves at December 31, 2017 increased by 9.0 MMBoe, or 24% primarily due to:

Extensions and Discoveries. We added 9.6 MMBoe of PUD reserves through extensions and discoveries primarily from our Tornado exploration prospect in the Phoenix Field.

Revisions of Previous Estimates. Negative revisions of PUD reserves of 0.6 MMBoe were primarily due to dropped PUD reserves of 3.8 MMBoe and downward revisions of 2.3 MMBoe offset by a 5.5 MMBoe increase in PUD reserves related to the reclassification of the Motormouth well in the Phoenix Field from proved developed reserves to PUD reserves as a result of a mechanical failure requiring a new wellbore. The dropped PUD reserves and downward revisions were caused by a new geological data and changes in overall project economics. Future development costs related to the PUD revisions increased by $66.0 million primarily due to higher estimated project costs in the Phoenix Field.

We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves. We have no PUD reserves that have remained undeveloped for five years or more after they were initially disclosed as PUD reserves, and no PUD reserves scheduled to be developed beyond five years from the date of being initially recognized as PUD reserves with the exception of two sidetrack wells from existing wellbores. The sidetrack wells are dependent on the life of the last producing zone. After the last zone has been depleted, we will utilize the original wellbore to sidetrack to the PUD objectives. The net estimated PUD reserves associated with these two sidetrack wells is 13.6 MBoe. We did not drill any PUD reserves during the year ended December 31, 2017, as we focused our 2017 capital program on the Zama-I deep water exploration project in the shallow waters offshore Mexico, Tornado II exploration prospect in the Phoenix Field and lower risk recompletion opportunities. However, the 2018 drilling program includes the Tornado III PUD in the deepwater a